UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                     Washington, D.C. 20549

                            FORM 10-K
<TABLE>
<CAPTION>
<S>    <C>
  [X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
       SECURITIES EXCHANGE ACT OF 1934
       For the fiscal year ended December 31, 2001

                                   OR
       TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
       SECURITIES EXCHANGE ACT OF 1934
       For the transition period from           to          .
</TABLE>
                 Commission file number 1-14768
                              NSTAR
     (Exact name of registrant as specified in its charter)
<TABLE>
<CAPTION>
<S>                                       <C>
              Massachusetts                      04-346630
       (State or other jurisdiction           (I.R.S. Employer
    of incorporation or organization)       Identification No.)

800 Boylston Street, Boston Massachusetts          02199
 (Address of principal executive offices)        (Zip Code)
</TABLE>
Registrant's telephone number, including area code: 617-424-2000

Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
<S>                                  <C>
                                       Name of each exchange on which
       Title of each class                       registered
 Common Shares, Par Value $1 per share    New York Stock Exchange
                                           Boston Stock Exchange
</TABLE>
Securities registered pursuant to Section 12(g) of the Act: None

  Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.  YES  X  NO
  Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form
10-K or any amendment to this Form 10-K.  [ X ]
  The aggregate market value of the voting stock held by non-
affiliates of the registrant as of March 15, 2002 computed as the
average of the high and low market price of the common shares as
reported in the listing of composite transactions for New York
Stock Exchange listed securities in the Wall Street Journal:
$2,354,645,042.
  Indicate the number of shares outstanding of each for the
registrant's classes of common stock, as of the latest
practicable date.
<TABLE>
<CAPTION>
<S>                                      <C>
               Class                       Outstanding at March 15,2002
     Common Shares, $1 par value                53,032,546 Shares

Documents Incorporated by Reference             Part in Form 10-K
Portions of the Registrant's Definitive        Parts I, II and III
 Proxy Statement Dated March 22, 2002
    (pages as specified herein)
</TABLE>

List of exhibits begins on page 77 of this report.

                              NSTAR
<TABLE>
<CAPTION>
            Form 10-K Annual Report December 31, 2001
<S>     <C>                                                        <C>
                                                                      Page
                               Part I

Item 1.  Business                                                       2
Item 2.  Properties                                                    11
Item 3.  Legal Proceedings                                             12
Item 4.  Submission of Matters to a Vote of Security Holders           13
Item 4A. Executive Officers of the Registrant                          14

                              Part II

Item 5.  Market for the Registrant's Common Equity and
         Related Stockholder Matters                                   15
Item 6.  Selected Consolidated Financial Data                          16
Item 7.  Management's Discussion and Analysis                          17
Item 7A. Quantitative and Qualitative Disclosures About Market Risk    41
Item 8.  Financial Statements and Supplementary Financial Information  42
Item 9.  Changes in and Disagreements with Accountants on
         Accounting and Financial Disclosure                           76

                              Part III

Item 10. Trustees and Executive Officers of the Registrant             76
Item 11. Executive Compensation                                        76
Item 12. Security Ownership of Certain Beneficial Owners and           76
         Management
Item 13. Certain Relationships and Related Transactions                76

                              Part IV

Item 14. Exhibits, Financial Statement Schedules and Reports           77
         on Form 8-K

</TABLE>
Part I

Item 1.   Business

(a) General Development of Business

NSTAR (or "the Company") is an energy delivery company serving
approximately 1.3 million customers in Massachusetts, including
approximately 1.1 million electric customers in 81 communities
and 246,000 gas customers in 51 communities.  NSTAR was created
through the merger of BEC Energy (BEC) and Commonwealth Energy
System (COM/Energy) on August 25, 1999 as an exempt public
utility holding company.  Its retail utility subsidiaries are
Boston Edison Company (Boston Edison), Commonwealth Electric
Company (ComElectric), Cambridge Electric Light Company
(Cambridge Electric) and NSTAR Gas Company (NSTAR Gas).  Its
wholesale electric subsidiary is Canal Electric Company (Canal
Electric).  NSTAR's three retail electric companies operate under
the brand name "NSTAR Electric."  Reference in this report to
"NSTAR Electric" shall mean each of Boston Edison, ComElectric
and Cambridge Electric.  NSTAR's non-utility operations include
telecommunications - NSTAR Communications, Inc. (NSTAR Com),
district heating and cooling operations (Advanced Energy Systems,
Inc. and NSTAR Steam Corporation) and a liquefied natural gas
service (Hopkinton LNG Corp.). Utility operations accounted for
approximately 96% of revenues in both 2001 and 2000.

The electric and natural gas industries have continued to change
in response to legislative, regulatory and marketplace demands
for improved customer service at lower prices.  These demands
have encouraged the utility industry to seek efficiencies and
other benefits through business combinations.  NSTAR is prepared
to operate in this changing marketplace by combining the
resources of its utility subsidiaries and concentrating its
activities in the transmission and distribution of energy.

NSTAR Electric has committed resources to implement a System
Improvement Program to better serve its customers by focusing on
improving customer service and system reliability.  This
comprehensive, non-recurring System Improvement Program was
implemented to upgrade NSTAR Electric's distribution system and
is expected to be completed by the third quarter of 2002.  The
cost of this non-recurring program is expected to be $65 million.
Approximately $11 million will be included in operations and
maintenance expense in 2002 and $54 million will be invested in
delivery assets (utility plant) during the year.  A combination
of unusually severe storms, record heat and extreme customer load
in the Boston area led to prolonged and wide-spread outages in
the summer of 2001 that underscored the need to address system
upgrades and improve maintenance.  NSTAR's peak demand electric
load reached an all-time level on August 9, 2001 of 4,527
megawatts (MW) and surpassed the prior year's peak load by 12%
and the previous all-time peak load by 8.5%.  The program
includes non-recurring costs to eliminate the backlog of critical
maintenance activities and complete non-routine systems
enhancements.

An integral part of the merger creating NSTAR is the rate plan of
the retail utility subsidiaries of BEC and COM/Energy that was
approved by the Massachusetts Department of Telecommunication and
Energy (MDTE) on July 27, 1999.  Significant elements of the rate
plan include a four-year distribution rate freeze, recovery of
the acquisition premium (goodwill) over 40 years and recovery of
transaction and integration costs (costs to achieve) over 10
years.  Refer to the "Retail Electric Rates" section in Item 7,
Management's Discussion and Analysis for more information.

In 1998, Boston Edison completed the sale of all of its fossil
generating assets and in 1999, sold its Pilgrim Nuclear
Generating Station.  COM/Energy sold substantially all of its
fossil generating assets in 1998.  Refer to the "Generating
Assets Divestiture" section in Item 7, Management's Discussion
and Analysis for more information.

(b) Financial Information about Industry Segments

NSTAR's principal operating segments are the electric and natural
gas utilities that provide energy delivery services in over 100
cities and towns in Massachusetts.  Refer to Note K of the
Consolidated Financial Statements in Item 8 for specific
financial information related to NSTAR's electric utility, gas
utility and unregulated segments.

(c) Narrative Description of Business

Principal Products and Services

NSTAR ELECTRIC
<TABLE>
<CAPTION>
NSTAR Electric operating revenues by class of customers for the
years 2001, 2000 and 1999 consisted of the following:
<S>                          <C>     <C>    <C>
Retail electric revenues:       2001   2000   1999

  Commercial                     51%    49%     51%
  Residential                    33%    33%     30%
  Industrial                      8%     9%      9%
  Other                           1%     1%      1%
Wholesale and contract revenues   7%     8%      9%
</TABLE>

The results for 2001 and 2000 reflect NSTAR for a full year,
while the results for 1999 reflect eight months of BEC and four
months of NSTAR.

NSTAR Electric currently supplies electricity at retail to an
area of 1,702 square miles.  The territory served includes the
city of Boston and 80 surrounding cities and towns including
Cambridge, New Bedford and Plymouth and the geographic area
comprising Cape Cod and Martha's Vineyard.  The population of the
area served with electricity at retail is approximately 2.3
million.  In 2001, NSTAR Electric served approximately 1.1
million customers.

  Sources and Availability of Electric Power Supply

NSTAR Electric has existing long-term power purchase agreements
that are expected to supply approximately 90%-95% of its standard
offer service obligations.  NSTAR Electric has entered into a
series of short-term power purchase agreements to meet its entire
default service supply obligations and its remaining unmet
standard offer supply obligations through December 31, 2002.
NSTAR Electric expects to continue to make periodic market
solicitations for default service and standard offer power supply
consistent with provisions of the Restructuring Act and MDTE
orders.

NSTAR Electric entered into six-month agreements effective
January 1, 2001 through June 30, 2001 and July 1, 2001 through
December 31, 2001 with suppliers to provide full default service
energy and ancillary service requirements at contract rates
substantially similar to MDTE-approved tariff rates.  NSTAR
Electric's existing portfolio of power purchase contracts
supplied the majority of its standard offer (including wholesale)
energy requirements in 2001, supplemented with long-term and
daily purchases/sales in the bilateral and spot markets.  In
addition, NSTAR Electric managed its Independent System Operator-
New England Power capability responsibilities, congestion and
uplift costs associated with default service and standard offer
load throughout 2001.  For further information refer to Note M of
the Consolidated Financial Statements in Item 8.

ComElectric had an 11% contract entitlement in the output of the
Pilgrim nuclear power plant that was sold by Boston Edison in
1999 to Entergy Nuclear Generating Company (Entergy).  Boston
Edison and ComElectric will buy power generated by the Pilgrim
plant from Entergy on a declining basis through 2004.

NSTAR Electric also has a 2.5% equity investment in the 540 MW
Vermont Yankee nuclear power plant.  NSTAR Electric is entitled
to electricity produced from the facility based on its ownership
interest, and is billed for its entitlement pursuant to a
contractual agreement that is approved by the FERC.  The
estimated cost to decommission this plant is $471.1 million in
current dollars. NSTAR Electric's share of this liability is
approximately $11.8 million, less its share of the market value
of the assets held in a decommissioning trust of approximately
$7.4 million, is approximately $4.4 million at December 31, 2001.
Vermont Yankee has received the approval of the FERC to include
charges for the estimated costs of decommissioning its unit in
the cost of energy that it sells.  Periodically, Vermont Yankee
re-estimates the cost of decommissioning and applies to the FERC
for increased rates in response to increased decommissioning
costs.  The Vermont Yankee unit was under agreement to be sold to
Amergen Energy Company (Amergen), but this transaction was
disapproved on February 14, 2001 by Vermont's regulatory
authority. Subsequently, in 2001, FERC approved an agreement
between Vermont Yankee and intervening parties that included,
among other things, a settlement on the regulatory treatment of
costs incurred in conjunction with initiatives, including Amergen
to sell the plant and related assets and liabilities.

On August 15, 2001, Vermont Yankee executed a Purchase and Sale
Agreement with the intent to sell the plant and related assets
and liabilities, including the liability to decommission the
plant, to Entergy Nuclear Vermont Yankee, LLC.  The sale of the
plant, as contemplated, would likely result in the transfer of
responsibility for decommissioning the plant to the new owner and
make future decommissioning collections unnecessary.
<TABLE>
<CAPTION>
As of December 31, 2001, information that relates to nuclear
units that are no longer operating in which NSTAR has an equity
ownership is as follows:
<S>                   <C>            <C>         <C>
                      Connecticut        Maine     Yankee
                          Yankee        Yankee     Atomic
                                (dollars in thousands)
Year of Shutdown            1996          1997       1992
Equity Ownership (%)          14             4         14
Equity Ownership Balance $ 9,573       $ 2,493      $  90
</TABLE>

  New England Power Pool (NEPOOL)

NEPOOL was restructured with changes taking effect to the
membership and governance provisions of the power pooling
agreement along with the transfer of operating responsibility of
the integrated transmission and generation system in New England
to ISO-New England.  Previously, NEPOOL dispatched generating
units for operation based on the lowest operating costs of
available generation and transmission.  Under the new structure,
generators are required to provide ISO-New England with market
prices at which they sell short-term energy supply.  These prices
formed the basis for dispatch that began in the second quarter of
1999.  As noted in the "Sources and Availability of Electric
Power Supply" section above, NSTAR Electric has existing long-
term power purchase contracts that have been supplying 90% - 95%
of its standard offer service obligations.  Therefore, the change
to NEPOOL's operations and pricing structure is expected to have
no material adverse impact on NSTAR's costs for purchased
electric energy.

  Retail Electric Rates

As a result of electric industry restructuring, NSTAR Electric
has unbundled its rates, provided customers with inflation-
adjusted rates that are 15 percent lower than rates in effect
prior to March 1, 1998 (the retail access date) and have afforded
customers the opportunity to purchase generation supply in the
competitive market.  Unbundled delivery rates are composed of a
customer charge (to collect metering and billing costs), a
distribution charge (to collect the costs of delivering
electricity), a transition charge (to collect past costs for
investments in generating plants and costs related to power
contracts), a transmission charge (to collect the cost of moving
the electricity over high voltage lines from a generating plant),
an energy conservation charge (to collect costs for demand-side
management programs) and a renewable energy charge (to collect
the cost to support the development and promotion of renewable
energy projects).  Electricity supply services provided by NSTAR
Electric include optional standard offer service and default
service.

Standard offer service is the electricity that is supplied to
eligible customers by the retail electric subsidiaries until a
competitive power supplier is chosen by the customer.  Customers
have the option of continuing to buy power from the retail
electric distribution businesses at standard offer prices through
2004.  The cost of providing standard offer service includes fuel
and purchased power costs.  Default service is the electricity
that is supplied by the local distribution company when a
customer is not receiving power from standard offer service.  The
market price for standard offer and default service will
fluctuate based on the average market price for power.  Amounts
collected through standard offer and default service are
recovered on a fully reconciling basis.

Prior to the implementation of industry restructuring on March 1,
1998, NSTAR Electric had Fuel Charge rate schedules that
generally allowed for current recovery, from retail customers, of
fuel used in electric production, purchased power and
transmission costs.

NSTAR Gas
<TABLE>
<CAPTION>
NSTAR Gas operating revenues by class of customers for the years
2001, 2000 and 1999 (effective September 1, 1999), consisted of
the following:
<S>                             <C>     <C>    <C>
                                 2001    2000   1999
Retail Gas revenues:
  Residential                     58%     59%    61%
  Commercial                      27%     24%    24%
  Industrial                       4%      3%     4%
  Other                            6%      8%     6%
Wholesale and contract revenues    5%      6%     5%
</TABLE>
Natural gas is distributed by NSTAR Gas to approximately 246,000
customers in 51 communities in central and eastern Massachusetts
covering 1,067 square miles and having an aggregate population of
1,176,000.  Twenty-five of these communities are also served by
NSTAR Electric with electricity.  Some of the larger communities
served by NSTAR Gas include Cambridge, Somerville, New Bedford,
Plymouth, Worcester, Framingham, Dedham and the Hyde Park area of
Boston.

  Gas Supply

NSTAR Gas purchases transportation, storage and balancing
services from Tennessee Gas Pipeline Company and Algonquin Gas
Transmission Company, as well as other upstream pipelines that
bring gas from major producing regions in the U.S. Gulf and
Canada to the final delivery points in the Company's service
area.  NSTAR Gas purchases all of its gas supplies from third-
party vendors, primarily under firm contracts with terms of less
than one year.  The vendors vary from small independent marketers
to major gas and oil producers.  Based on its firm pipeline
transportation capacity entitlements, NSTAR Gas contracts for up
to 140,309 Million British thermal units (MMBtu) per day of
domestic production.  In addition, NSTAR Gas has an agreement for
up to 4,500 MMBtu per day of Canadian supplies.  In November
2001, NSTAR Gas entered into a one-year full services firm supply
agreement with a major marketer in order to more fully optimize
its supply and transportation portfolio.  The agreement requires
the supplier to deliver all of NSTAR Gas' required pipeline
supplies utilizing the Company's upstream pipeline capacity.

In addition to firm transportation and gas supplies mentioned
above, NSTAR Gas utilizes contracts for underground storage and
liquefied natural gas ("LNG") facilities to meet its winter
peaking demands.  The LNG facilities, described below, are
located within NSTAR Gas' distribution system and are used to
liquefy and store pipeline gas during the warmer months for use
during the heating season. The underground storage contracts are
a combination of existing and new agreements that are the result
of FERC Order 636 service unbundling.  During the summer
injection season, excess pipeline capacity is used to deliver and
store gas in market area storage facilities, located in the New
York and Pennsylvania region.  Stored gas is withdrawn during the
winter season to supplement pipeline supplies in order to meet
firm heating demand.  NSTAR Gas has firm storage capacity
entitlements of over 7.5 billion cubic feet (Bcf).

A portion of the storage for gas supply for NSTAR Gas during the
winter heating season is provided by Hopkinton LNG Corp.
(Hopkinton), a wholly-owned subsidiary of NSTAR.  The facility
consists of a liquefaction and vaporization plant and three above-
ground cryogenic storage tanks having an aggregate capacity of 3
Bcf of natural gas.

In addition, Hopkinton owns a satellite vaporization plant and
two above-ground cryogenic storage tanks located in Acushnet,
Massachusetts with an aggregate capacity of .5 Bcf of natural gas
that are filled with LNG trucked from Hopkinton or purchased from
third parties.

NSTAR Gas has contracts for LNG storage service with Hopkinton
extending on a year-to-year basis with notice of termination
required five years in advance of the anticipated termination
date.  Current contract payments include a demand charge
sufficient to cover Hopkinton's fixed charges and an operating
charge that covers liquefaction and vaporization expenses.  NSTAR
Gas furnishes pipeline gas during the period April 15 to November
15 each year for liquefaction and storage.  As the need arises
during the winter season, LNG is vaporized and placed in the
distribution system to supplement pipeline and storage
deliveries.

Based upon information presently available regarding projected
growth in demand and estimates of availability of future supplies
of pipeline gas, NSTAR Gas believes that its present sources of
gas supply are adequate to meet existing load and allow for
future growth in sales.

  Off-system Gas Sales and Capacity Release Service

NSTAR Gas utilizes the off-system sales and capacity release
markets in order to optimize the value of its supply portfolio
and to mitigate the cost of any excess resources.  In 2001 the
Company elected to accomplish this through third parties that
provided guaranteed payments as compensation for use of any
available excess storage and transportation entitlements.  NSTAR
Gas retains 25% of the gross mitigation margins realized above a
certain threshold amount as set from year to year, with the
remaining margins credited to firm customers.  As a result of
this margin-sharing agreement, NSTAR Gas retained approximately
$636,000 and $189,000 in 2001 and 2000, respectively.

Natural Gas Industry Restructuring and Rates

Effective November 1, 2000, the MDTE approved regulations that
provide for full customer choice to LDCs (local gas distribution
companies) such as NSTAR Gas.  NSTAR Gas has modified its
billing, customer and gas supply systems to accommodate full
retail choice.  The MDTE previously had approved the compliance
process submitted by NSTAR Gas and other LDCs that implement the
unbundling of retail gas services to all customers.  Among the
important provisions are: setting the LDC as the default service
provider, certification of competitive suppliers/marketers,
extension of the MDTE's consumer protection rules to residential
customers taking competitive service, requirement for LDCs to
provide suppliers/marketers with customer usage data, and
requirement for suppliers/marketers to disclose service terms to
potential customers.  The MDTE has also ruled on requiring the
mandatory assignment of the LDC's upstream pipeline and storage
capacity and downstream peaking capacity to customers who elect a
competitive gas supply during a three-year transition period.
This eliminates potential stranded cost exposure for the LDCs
until they are relieved from their responsibility as suppliers of
last resort and the establishment of a "workably competitive"
interstate pipeline capacity market.  Gas restructuring is not
likely to have a significant adverse financial impact on LDCs.

NSTAR Gas generates revenues primarily through the sale and/or
transportation of natural gas.  Gas sales and transportation
services are divided into two categories: firm, whereby NSTAR Gas
must supply gas and/or transportation services to customers on
demand; and interruptible, whereby NSTAR Gas may, generally
during colder months, temporarily discontinue service to high
volume commercial and industrial customers.  Sales and
transportation of gas to interruptible customers do not
materially affect NSTAR Gas' operating income because
substantially all of the margin on such service is returned to
its firm customers as cost reductions.

In addition to delivery service rates, NSTAR Gas' tariffs include
a seasonal Cost of Gas Adjustment Clause (CGAC) and a Local
Distribution Adjustment Clause (LDAC).  The CGAC provides for the
recovery of all gas supply costs from firm sales customers or
default service customers.  The LDAC provides for the recovery of
certain costs applicable to both sales and transportation
customers.  The CGAC is filed semi-annually for approval by the
MDTE.  The LDAC is filed annually for approval.

In December 2000 and in a revised filing in January 2001, NSTAR
Gas filed for interim increases to its CGAC for the period
February through April 2001 in order to recover significant
increases in the costs to buy natural gas supplies.  These
filings were made to ensure that prices to customers are set at
levels that recover all incurred costs in order to avoid the
accumulation of significant under-recoveries that would impair
NSTAR Gas' ability to serve its customers.  On January 31, 2001,
the MDTE approved an adjustment to increase the CGAC factor to
$1.1123 per therm from the prior factor of $0.7608 per therm.
Subsequently, on February 28, 2001, as a result of a decline in
wholesale natural gas prices, NSTAR Gas received approval from
the MDTE to reduce the factor per therm to $0.9372 effective
March 1, 2001, and in conjunction with its semi-annual filing
made on March 15, 2001, NSTAR Gas proposed a CGAC factor of
$0.7754 per therm for the period commencing May 1, 2001 through
October 31, 2001.  This factor, approved by the MDTE, included
the collection in the summer period of a portion of the coming
winter's gas costs in order to reduce cost deferrals that were
projected for the end of October 2001.  In October 2001, due to
the significant decline in wholesale natural gas prices, NSTAR
Gas received approval from the MDTE to reduce the CGAC factor for
the period from November 1, 2001 through April 30, 2002 to
$0.5261 per therm.  In December 2001, NSTAR Gas received approval
to further reduce its CGAC factor by 17% to $0.4350 per therm
effective January 1, 2002.  In January 2002, NSTAR Gas again
filed and the MDTE approved a reduction of the NSTAR Gas CGAC
factor that became effective February 1, 2002 to $0.3834 per
therm as a result of the continuing decline in its supply costs.
This represented a 59% decrease from the weighted average factor
in effect during the prior winter season.

RCN Joint Venture and Investment Conversion

NSTAR Com is a participant in a telecommunications venture with
RCN Telecom Services, Inc. of Massachusetts, a subsidiary of RCN
Corporation (RCN). NSTAR Com has accounted for its equity
investment in the joint venture using the equity method of
accounting. As part of the Joint Venture Agreement, NSTAR Com has
the option to exchange portions of its joint venture interest for
common shares of RCN at specified periods.  NSTAR Com recognized
an impairment of its entire investment in RCN in the first
quarter of 2001.  For a further discussion on these exchanges and
other developments, refer to the "RCN Joint Venture and
Investment Conversion" section in Item 7, Management's Discussion
and Analysis for more information.

Franchises

Through their charters, which are unlimited in time, NSTAR
Electric and NSTAR Gas have the right to engage in the business
of distributing and selling electricity and natural gas and have
powers incidental thereto and are entitled to all the rights and
privileges of and subject to the duties imposed upon electric and
natural gas companies under Massachusetts laws.  The locations in
public ways for electric transmission and distribution lines or
gas distribution are obtained from municipal and other state
authorities which, in granting these locations, act as agents for
the state.  In some cases the actions of these authorities are
subject to appeal to the MDTE.  The rights to these locations are
not limited in time and are subject to the action of these
authorities and the legislature.  Pursuant to the Restructuring
Act enacted in November 1997, the MDTE has defined the service
territory of NSTAR Electric and NSTAR Gas based on the territory
actually served on July 1, 1997, and following, to the extent
possible, municipal boundaries.  The legislation further provided
that, until terminated by effect of law or otherwise, these
companies shall have the exclusive obligation to provide
distribution service to all retail customers within such service
territory.  No other entity shall provide distribution service
within this territory without the written consent of NSTAR
Electric and/or NSTAR Gas, which consent must be filed with the
MDTE and the municipality so affected.

Regulation

NSTAR Electric, NSTAR Gas, and Boston Edison's wholly owned
subsidiary, Harbor Electric Energy Company (HEEC), operate
primarily under the authority of the MDTE, whose jurisdiction
includes supervision over retail rates for distribution of
electricity, natural gas and financing and investing activities.
In addition, the FERC has jurisdiction over various phases of
NSTAR Electric and NSTAR Gas utility businesses, including rates
for electricity and natural gas sold at wholesale, facilities
used for the transmission or sale of that energy, certain
issuances of short-term debt and regulation of the system of
accounts.

Capital Expenditures and Financings
<TABLE>
<CAPTION>
The most recent estimates of capital expenditures and long-term
debt maturities requirements for the years 2002 through 2006 are
as follows:
<S>                      <C>       <C>       <C>       <C>       <C>
                            2002       2003      2004      2005     2006
                                            (in thousands)
Capital expenditures (1) $315,000   $229,000  $ 193,000 $168,000  $147,000
Long-term debt           $ 78,648   $241,168  $  78,659 $ 77,562  $ 98,024
</TABLE>

(1) Includes plant expenditures, capital requirements of non-
utility ventures and $54 million of costs related to a non-
recurring System Improvement Program.

Management continuously reviews its capital expenditure and
financing programs.  These programs and, therefore, the estimates
included in this Form 10-K are subject to revision due to changes
in regulatory requirements, environmental standards, availability
and cost of capital, interest rates and other assumptions.

Plant expenditures in 2001 were $228.7 million and consisted
primarily of additions to NSTAR's distribution and transmission
systems.  The majority of these expenditures were for system
reliability and control improvements, customer service
enhancements and capacity expansion to allow for long-range
growth in the NSTAR service territory.

Refer to the "Liquidity and Capital Resources" section of Item 7
for more information regarding capital resources to fund NSTAR's
construction programs.

Seasonal Nature of Business

Kilowatt-hour sales and revenues are typically higher in the
winter and summer than in the spring and fall as sales tend to
vary with weather conditions.  Refer to the Selected Consolidated
Quarterly Financial Data (Unaudited) in Item 6 for specific
financial information by quarter for 2001 and 2000.  NSTAR Gas'
sales are positively impacted by colder weather because a
substantial portion of its customer base uses natural gas for
space heating purposes.

Competitive Conditions

The electric and natural gas industries have continued to change
in response to legislative, regulatory and marketplace demands
for improved customer service at lower prices.  These pressures
have resulted in an increasing trend in the industry to seek
competitive advantages and other benefits through business
combinations. NSTAR was created to operate in this new
marketplace by combining the resources of its utility
subsidiaries in its activities in the transmission and
distribution of energy.

Environmental Matters

NSTAR's subsidiaries are subject to numerous federal, state and
local standards with respect to the management of wastes, air and
water quality and other environmental considerations.  These
standards could require modification of existing facilities or
curtailment or termination of operations at these facilities.
They could also potentially delay or discontinue construction of
new facilities and increase capital and operating costs by
substantial amounts.  Noncompliance with certain standards can,
in some cases, also result in the imposition of monetary civil
penalties.  Refer to the "Contingencies - Environmental Matters"
section in Item 7, Management's Discussion and Analysis for more
information.

Environmental-related capital expenditures for the years 2001 and
2000 were $0 and $4.5 million, respectively.  Management believes
that its remaining operating facilities are in substantial
compliance with currently applicable statutory and regulatory
environmental requirements.  Additional expenditures could be
required as changes in environmental requirements occur.

Number of Employees

As of December 31, 2001, NSTAR had approximately 3,300 full-time
employees, including approximately 2,300 or 70% of whom are
represented by two collective bargaining units covered by
separate contracts.  Effective in May 2001, all employees are
employed by NSTAR Electric & Gas Corporation (NSTAR Electric &
Gas).  As of December 2000, the management of NSTAR's utility
subsidiaries and eight separate utility union bargaining units
reached an agreement to merge most of the unionized workforce,
effective January 1, 2001, into Local 369 of the Utility Workers
Union of America, AFL-CIO.  The new agreement results in a single
bargaining unit of approximately 2,000 NSTAR Electric & Gas
employees with a five-year contract expiring May 15, 2005 that
replaced seven separate and widely diverse agreements.

A collective bargaining unit contract representing approximately
300 NSTAR Electric & Gas employees expires on March 31, 2002.  On
March 24, 2002, Local 12004, United Steelworkers of American, AFL-
CIO-CLC ratified a new four-year contract that expires on March
31, 2006.

Management believes it has satisfactory employee relations with a
significant majority of its employees.

(d) Financial Information about Foreign and Domestic Operations
and Export Sales

None of NSTAR's subsidiaries have any foreign operations or
export sales.

Item 2.   Properties

Substantially all of NSTAR Electric's fossil generating assets
were sold as of December 30, 1998.  The Pilgrim Nuclear
Generating Station was sold in 1999. NSTAR, through its Canal
Electric subsidiary, continues to retain a 3.52% interest (40.5
MW of capacity) in Seabrook 1.

Other NSTAR Electric properties include an integrated system of
distribution lines and substations that are located primarily in
the Boston area as well as the outlying communities, including
Plymouth, New Bedford, Cape Cod communities and Martha's
Vineyard.  In addition, NSTAR Electric's other principal
properties consist of an office building and other structures
such as garages and service buildings.

At December 31, 2001, the NSTAR Electric primary and secondary
transmission and distribution system consisted of approximately
20,200 circuit miles of overhead lines, approximately 8,400
circuit miles of underground lines, 261 substations and
approximately 1,109,000 active customer meters.

NSTAR Electric's high-tension transmission lines are generally
located on land either owned or subject to perpetual and
exclusive easements in its favor.  Its low-tension distribution
lines are located principally on public property under permission
granted by municipal and other state authorities.

The principal natural gas properties consist of distribution
mains, services and meters necessary to maintain reliable service
to customers.  At December 31, 2001, the gas system included
approximately 2,900 miles of gas distribution lines,
approximately 174,700 services and approximately 266,200 customer
meters together with the necessary measuring and regulating
equipment.  In addition, NSTAR (through Hopkinton) owns a
liquefaction and vaporization plant, a satellite vaporization
plant and above-ground cryogenic storage tanks having an
aggregate storage capacity equivalent to 3.5 Bcf of natural gas.
NSTAR Gas owns an office and service building in Southborough,
Massachusetts, five district office buildings and several natural
gas receiving and take stations.

In the third quarter of 2001, in conjunction with its corporate
facilities consolidation of approximately a third of its work
force, NSTAR completed construction of a 370,000 square foot
office building (the Summit) sited on 33 acres in the Boston
suburb of Westwood.  This site is centrally located in NSTAR's
service area and houses central administrative offices including
finance, human resources, sales, engineering, information
technology, and customer care.  NSTAR is expected, in 2002, to
close on a like-kind exchange of properties in Boston and
Cambridge for the Summit.

District heating and cooling operations primarily consist of the
Medical Area Total Energy Plant (MATEP) located in the Longwood
Medical Area of Boston.  MATEP provides steam, chilled water and
electricity to over 9 million square feet in medical and teaching
facilities.  NSTAR Steam Corporation's distribution system
consists primarily of approximately 3.5 miles of high pressure
steam lines to 21 customers in Cambridge and Boston.

HEEC, Boston Edison's regulated subsidiary, has a distribution
system that consists principally of a 4.1 mile 115 kV submarine
distribution line and a substation which is located on Deer
Island in Boston, Massachusetts.  HEEC provides the ongoing
support required to distribute electric energy to its only
customer, the Massachusetts Water Resources Authority, at this
location.

Item 3.   Legal Proceedings

  Industry and corporate restructuring legal proceedings

The 1998 MDTE order approving the Boston Edison electric
restructuring settlement agreement was appealed by certain
parties to the Massachusetts Supreme Judicial Court.  One appeal
remains pending.  However, there has to date been no briefing,
hearing or other action taken with respect to this proceeding.
Management is currently unable to determine the outcome of this
proceeding.  However, if an unfavorable outcome were to occur,
there could be a material adverse impact on business operations,
the consolidated financial position, cash flows and the results
of operations for a reporting period.

The 1999 MDTE order approving the rate plan associated with the
merger of BEC and COM/Energy was appealed by certain parties to
the Massachusetts Supreme Judicial Court.  The appeals of the AG
and a separate group that consists of The Energy Consortium and
Harvard University remain pending.  In October 2001, the MDTE
certified the record of the case to the court; however, there has
to date been no briefing, hearing or other action taken with
respect to this proceeding.  If an unfavorable outcome were to
occur, there could be a material adverse impact on business
operations, the consolidated financial position, cash flows and
the results of operations for a reporting period.

  Regulatory proceedings

In a Boston Edison reconciliation filing for 1999 with the MDTE
reflecting final costs and revenues through 1998, the AG
contested cost allocations related to Boston Edison's wholesale
customers.  On June 1, 2001, the MDTE approved Boston Edison's
revenue-credit approach for wholesale sales to be consistent with
Boston Edison's restructuring settlement.  The reconciliation of
wholesale revenues and costs, along with other reconciliation
issues, were addressed in Boston Edison's 2000 filing covering
the reconciliation of costs through December 31, 2000.  On
November 16, 2001, the MDTE approved a Settlement Agreement
between Boston Edison and the AG resolving all outstanding issues
in this filing.  This settlement agreement did not have a
material effect on NSTAR's consolidated financial position or
results of operations.

In October 1997, the MDTE opened a proceeding to investigate
Boston Edison's compliance with a 1993 order that permitted the
formation of Boston Energy Technology Group, Inc. (BETG) and
authorized Boston Edison to invest up to $45 million in non-
utility activities.  On December 28, 2001, the MDTE issued its
order ruling that Boston Edison exceeded the $45 million
investment cap set by the MDTE in 1993 by $3.9 million.  BETG was
ordered to return this amount to Boston Edison within 30 days.
This reimbursement occurred in January 2002.  Boston Edison was
also ordered to pay approximately $1.9 million representing
carrying charges on the over-investment amount since December 31,
1997 to current customers in the form of a credit to Boston
Edison's transition costs.  Accordingly, this credit has been
recorded and is included in the accompanying Consolidated Balance
Sheets as a reduction of Regulatory assets.  This change had no
material adverse effect on NSTAR's consolidated financial
position or results of operations.

  Other legal matters

In the normal course of its business, NSTAR and its subsidiaries
are also involved in certain other legal matters.  Management is
unable to fully determine a range of reasonably possible legal
costs in excess of amounts accrued.  Based on the information
currently available, it does not believe that it is probable that
any such additional costs will have a material impact on its
consolidated financial position.  However, it is reasonably
possible that additional legal costs that may result from a
change in estimates could have a material impact on the results
of a reporting period in the near term.

Item 4.   Submission of Matters to a Vote of Security Holders

There were no matters submitted to a vote of security holders
during the fourth quarter of 2001.

Item 4A.   Executive Officers of Registrant
<TABLE>
<CAPTION>
Identification of Executive Officers
<S>                   <C>                                  <C>
                                                                 Age
                                                             December 31,
Name of Officer         Position and Business Experience         2001

Thomas J. May           Chairman of the Board, President          54
                        (since 2002), Chief Executive
                        Officer and a Director/Trustee
                        (since 1999), formerly Chairman of
                        the Board, President and Chief
                        Executive Officer and a Trustee
                        (1998-1999), BEC Energy, and
                        Chairman of the Board, President
                        and Chief Executive Officer and a
                        Director (1995-1999), Boston
                        Edison Company; Director,
                        FleetBoston Financial; Liberty
                        Mutual Holding Company Inc.; New
                        England Business Services, Inc.
                        and RCN Corporation.

Douglas S. Horan        Senior Vice President/Strategy,          51
                        Law & Policy, Clerk and General
                        Counsel, (since 1999); formerly
                        Senior Vice President-Strategy and
                        Law and General Counsel, BEC
                        Energy (1998-1999) and Boston
                        Edison Company (1995-1999).

James J. Judge          Senior Vice President, Treasurer          45
                        and Chief Financial Officer,
                        (since 2000); formerly Senior Vice
                        President and Chief Financial
                        Officer, (1999-2000); formerly
                        Senior Vice President-Corporate
                        Services and Treasurer, BEC Energy
                        (1998-1999); and Senior Vice
                        President-Corporate Services and
                        Treasurer, Boston Edison Company
                        (1995-1999).

Eugene J. Zimon         Senior Vice President/Information         53
                        Technology, (since 2001).

Werner J. Schweiger     Senior Vice President/Operations,         42
                        (since 2002).

Joseph R. Nolan, Jr.    Senior Vice President - Corporate         38
                        Relations, (since 2000); formerly
                        Vice President of Government
                        Affairs, (1999-2000); Director of
                        Regulatory Relations, BEC Energy
                        (1998-1999); and Manager of
                        Legislative Affairs, Boston Edison
                        Company (1994-1998);

Robert J. Weafer, Jr.   Vice President, Controller and            54
                        Chief Accounting Officer, (since
                        1999); formerly Vice President,
                        Controller and Chief Accounting
                        Officer, BEC Energy (1998-1999)
                        and Boston Edison Company (1991-
                        1998).
</TABLE>
                             Part II

Item 5.   Market for the Registrant's Common Stock and Related
Stockholder Matters

(a) Market Information

NSTAR's common shares are listed on the New York and Boston Stock
Exchanges.
NSTAR's closing market price at December 31, 2001 was $44.85 per
share.
<TABLE>
<CAPTION>
The high and low market value per common share as reported in the
Wall Street Journal for each of the quarters in 2001 and 2000 was
as follows.
<S>                 <C>       <C>      <C>      <C>
                           2001               2000
                       High     Low      High       Low
 First quarter      $42.6875  $33.9375  $47.00    $38.25
 Second quarter     $43.85    $36.78    $46.125   $40.375
 Third quarter      $45.05    $39.50    $44.5625  $39.00
 Fourth quarter     $45.24    $40.10    $43.1875  $36.375
</TABLE>
(b) Holders

As of December 31, 2001, there were 29,890 holders of NSTAR
common shares.

(c) Dividends
<TABLE>
<CAPTION>
Dividends declared per common share for each of the quarters in
2001 and 2000 were as follows.
<S>                <C>          <C>
                       2001        2000
 First quarter       $0.515       $0.500
 Second quarter      $0.515       $0.500
 Third quarter       $0.515       $0.500
 Fourth quarter      $0.53        $0.515

 </TABLE>


Item 6.   Selected Consolidated Financial Data
<TABLE>
<CAPTION>
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.
<S>                <C>           <C>          <C>         <C>        <C>
                        2001          2000        1999(c)     1998       1997
Operating revenues   $3,191,836    $2,692,762  $1,851,427  $1,622,515  $1,778,531
Net income (a)       $    3,201    $  180,962  $  146,463  $  141,046  $  144,642
Earnings (loss)per
share of common stock:
  Basic (a)          $   (0.05)    $     3.19  $     2.77  $     2.76  $     2.71
  Diluted (a)        $   (0.05)    $     3.18  $     2.76  $     2.75  $     2.71
Total assets         $5,328,191    $5,547,715  $5,466,143  $3,204,036  $3,622,347
Long-term debt (b)   $1,377,899    $1,440,431  $  986,843  $  955,563  $1,057,076
Transition property
securitization
certificates (b)     $  513,904    $  584,130  $  646,559  $        -  $        -
Redeemable preferred
 stock (b)           $   43,000    $   43,000  $   92,279  $   92,040  $  163,093
Cash dividends
declared per
common share         $    2.075    $    2.015  $    1.955  $    1.895  $     1.88
</TABLE>

(a)  2001 includes the impact of a non-cash, after-tax charge of
$173.9 million, or $3.28 per share, related to NSTAR's
investment in RCN Corporation.

(b)  Excludes the current portion of long-term debt or preferred
stock.

(c)  Due to the application of the purchase method of accounting,
the results for 1999 reflect eight months of BEC Energy and
four months of NSTAR.
<TABLE>
<CAPTION>
Selected Consolidated Quarterly Financial Data (Unaudited)

(in thousands, except earnings per share)
<S>               <C>         <C>       <C>      <C>           <C>
                                                                    Basic
                                                                  Earnings
                                                    Earnings       (Loss)
                                                     (Loss)          Per
                                           Net      Available      Average
                    Operating  Operating  Income   for Common      Common
                    Revenues     Income   (Loss)  Shareholders    Share (b)
2001
First quarter (a)   $864,822  $ 89,268  $(132,256)  $(133,746)   $ (2.52)
Second quarter      $732,273  $ 81,677  $  37,710   $  36,220    $  0.68
Third quarter       $890,748  $114,983  $  68,636   $  67,146    $  1.27
Fourth quarter      $703,993  $ 64,833  $  29,111   $  27,954    $  0.52

2000
First quarter       $658,518  $ 79,401  $  37,099   $  35,609    $  0.62
Second quarter      $630,194  $ 76,955  $  32,928   $  31,438    $  0.57
Third quarter       $709,519  $126,864  $  66,286   $  64,796    $  1.21
Fourth quarter      $694,531  $ 91,074  $  44,649   $  43,159    $  0.81
</TABLE>

(a) Includes impact of a non-cash, after-tax charge of $173.9
million, or $3.28 per share, related to NSTAR's investment in RCN
Corporation.

(b) The sum of the quarters for 2000 may not equal basic annual
earnings per average common share since the result is based on
the weighted average number of common shares outstanding each
quarter.

Item 7.   Management's Discussion and Analysis

Overview

NSTAR (or "the Company") is an energy delivery company serving
approximately 1.3 million customers in Massachusetts, including
approximately 1.1 million electric customers in 81 communities
and 246,000 gas customers in 51 communities.  NSTAR was created
through the merger of BEC Energy (BEC) and Commonwealth Energy
System (COM/Energy) on August 25, 1999 as an exempt public
utility holding company.  Its retail utility subsidiaries are
Boston Edison Company (Boston Edison), Commonwealth Electric
Company (ComElectric), Cambridge Electric Light Company
(Cambridge Electric) and NSTAR Gas Company (NSTAR Gas).  Its
wholesale electric subsidiary is Canal Electric Company (Canal).
NSTAR's three retail electric companies operate under the brand
name "NSTAR Electric."  Reference in this report to "NSTAR
Electric" shall mean each of Boston Edison, ComElectric and
Cambridge Electric.  NSTAR's non-utility operations include
telecommunications - NSTAR Communications, Inc. (NSTAR Com),
district heating and cooling operations (Advanced Energy Systems,
Inc. and NSTAR Steam Corporation) and a liquefied natural gas
service company (Hopkinton LNG Corp.).  Utility operations
accounted for approximately 96% of revenues in both 2001 and
2000.

The electric and natural gas industries have continued to change
in response to legislative, regulatory and marketplace demands
for improved customer service at lower prices.  These demands
have encouraged the utility industry to seek efficiencies and
other benefits through business combinations.  NSTAR is prepared
to operate in this changing marketplace by combining the
resources of its utility subsidiaries and concentrating its
activities in the transmission and distribution of energy.

NSTAR Electric has committed resources to implement a System
Improvement Program to better serve its customers by focusing on
improving customer service and system reliability.  This
comprehensive, non-recurring System Improvement Program was
implemented to upgrade NSTAR Electric's distribution system and
is expected to be completed during 2002.  The cost of this non-
recurring program is expected to be $65 million.  Approximately
$11 million will be included in operations and maintenance
expense in 2002 and $54 million will be invested in delivery
assets during the year.  A combination of unusually severe
storms, record heat and extreme customer load in the Boston area
led to prolonged and wide-spread outages in the summer of 2001
that underscored the need to address system upgrades and improve
maintenance.  NSTAR's peak demand electric load reached an all-
time level on August 9, 2001 of 4,527 megawatts (MW) and
surpassed the prior year's peak load by 12% and the previous all-
time peak load by 8.5%.  The program includes non-recurring costs
to eliminate the backlog of critical maintenance activities and
complete non-routine systems enhancements.

Cautionary Statement

This Management's Discussion and Analysis contains certain
forward-looking statements such as forecasts and projections of
expected future performance or statements of management's plans
and objectives.  These forward-looking statements may be
contained in filings with the Securities and Exchange Commission
(SEC) and in press releases and oral statements.  You can
identify these statements by the fact that they do not relate
strictly to historical or current facts.  They use words such as
"anticipate," "estimate," "expect," "project," "intend," "plan,"
"believe" and other words and terms of similar meaning in
connection with any discussion of future operating or financial
performance.  These statements are based on the current
expectations, estimates or projections of management and are not
guarantees of future performance.  Some or all of these forward-
looking statements may not turn out to be what the Company
expected.  Actual results could potentially differ materially
from these statements.  Therefore, no assurance can be given that
the outcomes stated in such forward-looking statements and
estimates will be achieved.

The impact of continued cost control procedures on operating
results could differ from current expectations.  NSTAR's revenues
from its electric and gas sales are weather-sensitive,
particularly sales to residential and commercial customers.
Accordingly, NSTAR's sales in any given period reflect, in
addition to other factors, the impact of weather, with colder
temperatures generally resulting in increased gas sales and
warmer temperatures generally resulting in increased electric
sales.  NSTAR anticipates that these sensitivities to seasonal
and other weather conditions will continue to impact its sales
forecasts in future periods.  The effects of changes in weather,
economic conditions, tax rates, interest rates, technology,
prices and availability of operating supplies could materially
affect the projected operating results.

NSTAR undertakes no obligation to publicly update forward-looking
statements, whether as a result of new information, future
events, or otherwise.  You are advised, however, to consult any
further disclosures NSTAR makes in its Forms 10-Q and 8-K to the
SEC.  Also note that NSTAR provides in the next paragraph a
cautionary discussion of risks and other uncertainties relative
to its business.  These are factors that could cause its actual
results to differ materially from expected and historical
performance.  Other factors in addition to those listed here
could also adversely affect NSTAR.

NSTAR's forward-looking information depends in large measure on
prevailing governmental policies and regulatory actions,
including those of the Massachusetts Department of
Telecommunications and Energy (MDTE) and the Federal Energy
Regulatory Commission (FERC), with respect to allowed rates of
return, rate structure, financings, purchased power and cost of
gas recovery, acquisition and disposition of assets, operation
and construction of facilities, changes in tax laws and policies
and changes in and compliance with environmental and safety laws
and policies.

The impacts of various environmental, legal issues, and
regulatory matters could differ from current expectations.  New
regulations or changes to existing regulations could impose
additional operating requirements or liabilities other than
expected.  The effects of changes in specific hazardous waste
site conditions and the specific cleanup technology could affect
the estimated cleanup liabilities. The impacts of changes in
available information and circumstances regarding legal issues
could affect any estimated litigation costs.

Generating Assets Divestiture

On October 26, 2000, the MDTE approved the filing made by
ComElectric and Cambridge Electric (together, "the Companies")
for the partial buydown of their contract with Canal for power
from the Seabrook nuclear generating facility (Seabrook).  In
November 2000, a total of $141.6 million of funds held by an
affiliate, Energy Investment Services, Inc. (EIS), was
transferred to the Companies.  EIS was established as the vehicle
to invest the net proceeds from the sale of the Companies'
generation assets.  The Companies, in turn, reduced their
respective future costs to be recovered from customers.  The FERC
and the MDTE approved Canal's request to reflect the buydown
effective November 1, 2000.  Canal, along with other joint-owners
of Seabrook, has begun to actively market the sale of Seabrook.

In July 1999, Boston Edison completed the sale of the Pilgrim
Nuclear Generating Station to Entergy Nuclear Generating Company
(Entergy), a subsidiary of Entergy Corporation, for $81 million.
In addition to the amount received from the buyer, Boston Edison
received a total of approximately $233 million from the Pilgrim
contract customers, including $103 million from ComElectric, to
terminate their contracts.  As part of the sale, Boston Edison,
transferred its decommissioning trust fund to Entergy.  In order
to provide Entergy with a fully funded decommissioning trust
fund, Boston Edison contributed approximately $271 million to the
fund at the time of the sale.  As a result of a favorable
Internal Revenue Service tax ruling, Boston Edison received $43
million from Entergy reflecting a reduction in the required
decommissioning funding.  The difference between the total
proceeds received and the net book value of the Pilgrim assets
sold plus the net amount to fully fund the decommissioning trust
is included in Regulatory assets on the accompanying Consolidated
Balance Sheets as such amounts are currently being collected from
customers under Boston Edison's settlement agreement.

Rate and Regulatory Proceedings

An integral part of the merger creating NSTAR is the rate plan of
the retail utility subsidiaries of BEC and COM/Energy that was
approved by the MDTE on July 27, 1999.  Significant elements of
the rate plan include a four-year distribution rate freeze,
recovery of the acquisition premium (goodwill) over 40 years and
recovery of transaction and integration costs (costs to achieve)
over 10 years.  Refer to the "Retail Electric Rates" section of
this Management's Discussion and Analysis for more information.

Goodwill relating to the merger amounted to approximately $490
million, resulting in annual amortization of goodwill of
approximately $12.2 million.  Costs to achieve are being
amortized based on the filed estimate of $111 million over 10
years.  NSTAR's retail utility subsidiaries will reconcile the
ultimate costs to achieve with that estimate, and any difference
is expected to be recovered over the remainder of the
amortization period commencing in 2003.  A majority of costs to
achieve the merger were severance costs associated with a
voluntary separation program (VSP) in which approximately 700
employees elected to participate.  The VSP was completed by the
end of August 2000.  These amounts are offset by ongoing cost
savings from streamlined operations and avoidance of costs that
would have otherwise been incurred by BEC and COM/Energy.  Refer
to the "New Accounting Principles" section of this Management's
Discussion and Analysis for further information.

In a Boston Edison reconciliation filing for 1999 with the MDTE
reflecting final costs and revenues through 1998, the
Massachusetts Attorney General (AG) contested cost allocations
related to Boston Edison's wholesale customers.  On June 1, 2001,
the MDTE approved Boston Edison's revenue-credit approach for
wholesale sales to be consistent with Boston Edison's
restructuring settlement.  The reconciliation of wholesale
revenues and costs, along with other reconciliation issues, were
addressed in Boston Edison's 2000 filing covering the
reconciliation of costs through December 31, 2000.  On November
16, 2001, the MDTE approved a Settlement Agreement between Boston
Edison and the AG resolving all outstanding issues in this
filing.  This settlement agreement did not have a material effect
on NSTAR's consolidated financial position or results of
operations.

In October 1997, the MDTE opened a proceeding to investigate
Boston Edison's compliance with a 1993 order that permitted the
formation of Boston Energy Technology Group, Inc. (BETG) and
authorized Boston Edison to invest up to $45 million in non-
utility activities.  On December 28, 2001, the MDTE issued its
order ruling that Boston Edison exceeded the $45 million
investment cap set by the MDTE in 1993 by $3.9 million.  BETG was
ordered to return this amount to Boston Edison within 30 days.
This reimbursement occurred in January 2002.  Boston Edison was
also ordered to pay approximately $1.9 million representing
carrying charges on the over-investment amount since December 31,
1997 to current customers in the form of a credit to Boston
Edison's transition costs.  Accordingly, this credit has been
recorded and is included in the accompanying Consolidated Balance
Sheets as a reduction of Regulatory assets.  This charge had no
material adverse effect on NSTAR's consolidated financial
position or results of operations.

On June 13, 2001, the MDTE approved a settlement agreement
between Cambridge Electric and the Massachusetts Institute of
Technology (MIT) involving a dispute over the customer transition
charge (CTC) assessed by Cambridge Electric to MIT.  Under the
settlement, Cambridge Electric refunded approximately $1.7
million to MIT and MIT withdrew (i) its appeal at the
Massachusetts Supreme Judicial Court of the MDTE's rate order
associated with the merger of BEC Energy and COM/Energy and (ii)
its separate rate complaint at the MDTE involving the CTC.

On October 29, 2001, and as subsequently updated, NSTAR Electric
and NSTAR Gas each filed with the MDTE proposed service quality
plans for each company, which replaced the service quality plan
that had previously been filed as a part of the NSTAR merger rate
plan and includes guidelines that had been established by the
MDTE as a result of its generic investigation of service quality
issues.  The service quality plans established performance
benchmarks effective January 1, 2002 for certain identified
measures of service quality relating to customer service and
billing performance, customer satisfaction, and reliability and
safety performance.  The companies are required to report
annually concerning their performance as to each measure and are
subject to maximum penalties of up to two percent of transmission
and distribution revenues should performance fail to meet the
applicable benchmarks.  On October 29, 2001, NSTAR Electric and
NSTAR Gas also filed with the MDTE a report concerning their
performance on the identified service quality measures for the
two twelve-month periods ended August 31, 2000 and 2001.  This
report included a calculation of penalties in accordance with
MDTE guidelines whereby penalties were calculated totaling
approximately $3.9 million relating primarily to Boston Edison's
electric system reliability performance for the summer of 2001.
NSTAR disputes the legal applicability of penalties for these
performance periods; however, NSTAR proposed in settlement of
this matter to provide credits to Boston Edison customers
totaling $3.9 million, offset in part by other payments to Boston
Edison customers, which totaled approximately $1 million,
relating to summer 2001 electric service outages.  On March 22,
2002, following hearings on the matter, the MDTE issued an order
imposing a service quality penalty of approximately $3.25 million
to be refunded to customers as a credit to their bills in 2002.

Also on October 29, 2001, NSTAR Electric filed with the MDTE a
comprehensive report regarding electric system performance issues
encountered during the summer of 2001.  The filing included
detailed analyses of factors affecting performance, as well as,
the companies' plans to address issues identified.  The MDTE also
requested similar filings from other Massachusetts electric
distribution companies and has held public hearings and will hold
adjudicatory hearings concerning each such filing.  On January
30, 2002, the AG and the Massachusetts Division of Energy
Resources (DOER) filed comments urging the MDTE to assess the
maximum penalties allowed pursuant to the established service
quality benchmarks and to require an independent management audit
as a result of alleged service quality deficiencies.  On February
6, 2002, NSTAR Electric filed its brief arguing against the AG's
and DOER's positions.  On March 22, 2002, following a number of
public hearings throughout the NSTAR Electric service area, the
MDTE issued an order finding that NSTAR Electric had made
progress in addressing the issues which initiated the
investigation and requiring that NSTAR Electric submit further
updated reports on specific issues on a quarterly and annual
basis.  NSTAR is unable to estimate its ultimate liability for
future costs or penalties as a result of any further filings
relating to this investigation.  However, in view of NSTAR's
current assessment of its electric distribution system
performance responsibilities, existing legal requirements and
regulatory policies, management believes it would not have a
material effect on NSTAR's consolidated financial position, cash
flows or results of operations for a reporting period.

Retail Electric Rates

All distribution customers must pay a transition charge as a
component of their rate.  The purpose of the transition charge is
to allow for the collection of generation-related costs that
would not be collected in the competitive energy supply market.
The plant and regulatory asset balances that will be recovered
through the transition charge are approved by the MDTE in annual
filings by the NSTAR Electric companies.  The current schedule
for cost recovery through the transition charge is: Boston Edison
through 2016, Cambridge Electric and ComElectric through 2026.
This schedule is subject to adjustment by the MDTE.

The 1997 Restructuring Act requires electric distribution
companies to obtain and resell power to retail customers who
choose not to buy energy from a competitive energy supplier
through either standard offer service or default service.
Standard offer service will be available to eligible customers
through 2004 at prices approved by the MDTE, set at levels so as
to guarantee mandatory overall rate reductions provided by the
Restructuring Act.  New retail customers in the NSTAR Electric
service territories and other customers who are no longer
eligible for standard offer service and have not chosen to
receive service from a competitive supplier are provided default
service.  The price of default service is intended to reflect the
average competitive market price for power.  As of December 31,
2001, NSTAR Electric had approximately 16% of its load
requirements provided by competitive suppliers.

NSTAR Electric's accumulated cost to provide default and standard
offer service was in excess of the revenues it was allowed to
bill.  As a result, NSTAR reflected a regulatory asset of
approximately $242.7 million at December 31, 2000 that is
reflected as a component of Regulatory assets on the accompanying
Consolidated Balance Sheets.  NSTAR Electric was permitted by the
MDTE to increase its rates charged to customers to collect this
shortfall.  As a result of new rates for standard offer and
default service that became effective January 1 and July 1, 2001,
and the reduction in power supply costs in 2001, the regulatory
asset has declined to $45.4 million as of December 31, 2001.

In December 2000, the MDTE approved a standard offer fuel index
of 1.321 cents per kilowatt-hour (kWh) that was added to each
NSTAR Electric company's standard offer service rates for the
first half of 2001.  In June 2001, the MDTE approved an
additional increase of 1.23 cents per kWh effective July 1, 2001
based on a fuel adjustment formula contained in its standard
offer tariffs to reflect the prices of natural gas and oil.  In
December 2001, the MDTE approved a decrease in this fuel index of
1.125 cents to 1.426 cents per kWh for the first quarter of 2002
based on a decrease in the cost of fuel.  The MDTE has ruled that
these fuel index adjustments are excluded from the 15% rate
reduction requirement under the Restructuring Act.

NSTAR Electric must, on an annual basis, file a forecast of its
rates for the upcoming year along with any reconciliation of
prior year revenues and costs for standard offer, default
service, transmission and transition charges.  The MDTE will, in
the ordinary course, approve rates for the coming year before the
current year-end to allow the new rates to become effective the
first of January.  Subsequently, the estimates for the prior year
are reconciled to the actual amounts for that year.  The MDTE
reviews these costs and approves the amounts subject to any
required adjustments.

In December 2001, NSTAR Electric made filings containing proposed
rate adjustments for 2002, including a preliminary reconciliation
of costs and revenues through 2001.  The MDTE subsequently
approved tariffs for each retail electric subsidiary effective
January 1, 2002.  The filings were updated in February 2002 to
include final costs for 2001.  The MDTE has approved the
reconciliation of costs and revenues for Boston Edison through
2000 in its approval on November 16, 2001 of a Settlement
Agreement between Boston Edison and the AG resolving all
outstanding issues in Boston Edison's prior reconciliation
filings.  As a part of this settlement, Boston Edison agreed to
reduce the costs sought to be collected through the transition
charge by approximately $2.9 million as compared to the amounts
that were originally sought.  This settlement did not have a
material adverse effect on NSTAR's consolidated financial
position or results of operations for the period ended December
31, 2001.

On June 1, 2001, the MDTE issued its final orders on the
reconciliation of ComElectric and Cambridge Electric's
transition, standard offer service, default service and
transmission costs and revenues for 1998.  Reconciliation
proceedings for ComElectric and Cambridge Electric reflecting
costs and revenues for 1999 and 2000 remain open with hearings
not yet having taken place.  Management is unable to determine
the outcome of the remaining MDTE proceedings.  However, based
upon past procedures and on information currently available,
management does not believe that it is probable that the final
MDTE approval will have a material adverse impact on NSTAR's
consolidated financial position, results of operations and cash
flows.

In addition to the annual rate filings referenced above, NSTAR
Electric has also made interim filings with the MDTE concerning
charges for a standard offer fuel adjustment and for (market-
based) default service rates.  NSTAR Electric has existing long-
term power purchase agreements that are expected to supply
approximately 90%-95% of its standard offer service obligations.
NSTAR Electric has entered into a series of power purchase
agreements to meet its entire default service supply obligations
and its remaining unmet standard offer supply obligations through
December 31, 2002.  NSTAR Electric expects to continue to make
periodic market solicitations for default service and standard
offer power supply consistent with provisions of the
Restructuring Act and MDTE orders.  At December 31, 2001,
approximately 29% of NSTAR Electric's customers were on default
service.

Natural Gas Industry Restructuring and Rates

Effective November 1, 2000, the MDTE approved regulations that
provide for full customer choice to LDCs (local gas distribution
companies) such as NSTAR Gas.  NSTAR Gas has modified its
billing, customer and gas supply systems to accommodate full
retail choice.  The MDTE previously had approved the compliance
process submitted by NSTAR Gas and other LDCs that implement the
unbundling of retail gas services to all customers.  Among the
important provisions are: setting the LDC as the default service
provider, certification of competitive suppliers/marketers,
extension of the MDTE's consumer protection rules to residential
customers taking competitive service, requirement for LDCs to
provide suppliers/marketers with customer usage data, and
requirement for suppliers/marketers to disclose service terms to
potential customers.  The MDTE has also ruled on requiring the
mandatory assignment of the LDC's upstream pipeline and storage
capacity and downstream peaking capacity to customers who elect a
competitive gas supply during a three-year transition period.
This eliminates potential stranded cost exposure for the LDCs
until they are relieved from their responsibility as suppliers of
last resort and the establishment of a "workably competitive"
interstate pipeline capacity market.  Gas restructuring is not
likely to have a significant adverse financial impact on LDCs.

NSTAR Gas generates revenues primarily through the sale and/or
transportation of natural gas.  Gas sales and transportation
services are divided into two categories: firm, whereby NSTAR Gas
must supply gas and/or transportation services to customers on
demand; and interruptible, whereby NSTAR Gas may, generally
during colder months, temporarily discontinue service to high
volume commercial and industrial customers.  Sales and
transportation of gas to interruptible customers do not
materially affect NSTAR Gas' operating income because
substantially all of the margin on such service is returned to
its firm customers as cost reductions.

In addition to delivery service rates, NSTAR Gas' tariffs include
a seasonal Cost of Gas Adjustment Clause (CGAC) and a Local
Distribution Adjustment Clause (LDAC).  The CGAC provides for the
recovery of all gas supply costs from firm sales customers or
default service customers.  The LDAC provides for the recovery of
certain costs applicable to both sales and transportation
customers.  The CGAC is filed semi-annually for approval by the
MDTE.  The LDAC is filed annually for approval.

In December 2000 and in a revised filing in January 2001, NSTAR
Gas filed for interim increases to its CGAC for the period
February through April 2001 in order to recover significant
increases in the costs to buy natural gas supplies.  These
filings were made to ensure that prices to customers are set at
levels that recover all incurred costs in order to avoid the
accumulation of significant under-recoveries that would impair
NSTAR Gas' ability to serve its customers.  On January 31, 2001,
the MDTE approved an adjustment to increase the CGAC factor to
$1.1123 per therm from the prior factor of $0.7608 per therm.
Subsequently, on February 28, 2001, as a result of a decline in
wholesale natural gas prices, NSTAR Gas received approval from
the MDTE to reduce the factor per therm to $0.9372 effective
March 1, 2001, and in conjunction with its semi-annual filing
made on March 15, 2001, NSTAR Gas proposed a CGAC factor of
$0.7754 per therm for the period commencing May 1, 2001 through
October 31, 2001.  This factor, approved by the MDTE, included
the collection in the summer period of a portion of the coming
winter's gas costs in order to reduce cost deferrals that were
projected for the end of October 2001.  In October 2001, due to
the significant decline in wholesale natural gas prices, NSTAR
Gas received approval from the MDTE to reduce the CGAC factor for
the period from November 1, 2001 through April 30, 2002 to
$0.5261 per therm.  In December 2001, NSTAR Gas received approval
to further reduce its CGAC factor by 17% to $0.4350 per therm
effective January 1, 2002.  In January 2002, NSTAR Gas again
filed and the MDTE approved a reduction of the NSTAR Gas CGAC
factor that became effective February 1, 2002 to $0.3834 per
therm as a result of the continuing decline in its supply costs.
This represented a 59% decrease from the weighted average factor
in effect during the prior winter season.

Other Legal Matters

In the normal course of its business, NSTAR and its subsidiaries
are also involved in certain other legal matters.  Management is
unable to fully determine a range of reasonably possible legal
costs in excess of amounts accrued.  Based on the information
currently available, it does not believe that it is probable that
any such additional costs will have a material impact on its
consolidated financial position.  However, it is reasonably
possible that additional legal costs that may result from changes
in estimates could have a material impact on the results for a
reporting period.

Other Matters

The September 11, 2001 terrorist attack that occurred in New York
City and in Washington, D.C., resulted in a tremendous loss of
life and property.  This unfortunate incident has had
unprecedented pervasive negative impacts on several U.S.
industries and on the U.S. economy in general.  While NSTAR was
not directly impacted by the event, the Company believes that it
could be impacted indirectly in the near future.  The indirect
impacts may include lower revenues due to the negative impact on
certain of NSTAR's commercial and industrial customers and higher
costs related to items such as insurance and security.

Results of Operations

The following section of Management's Discussion and Analysis
compares the results of operations for each of the three fiscal
years ended December 31, 2001 and should be read in conjunction
with the consolidated financial statements and the accompanying
notes included elsewhere in this report.

2001 versus 2000

NSTAR's energy delivery businesses continue to be subject to
traditional utility accounting and ratemaking principles since
NSTAR earns a regulated equity return on its investments in those
businesses.
<TABLE>
<CAPTION>
Earnings (loss) per common share were as follows:
<S>                       <C>         <C>        <C>
                                Years ended December 31,

                               2001      2000    % Change
 Basic -
 After RCN charge            $(0.05)    $3.19     (101.6)
 Before RCN charge           $ 3.23     $3.19        1.3

 Diluted -
 After RCN charge            $(0.05)    $3.18     (101.6)
 Before RCN charge           $ 3.22     $3.18        1.3
</TABLE>

For 2001 NSTAR reported a loss of $2.4 million or $0.05 per basic
and diluted common share, compared to earnings for 2000 of $175
million or $3.19 and $3.18 per basic and diluted common share,
respectively.  Earnings for 2001 were $171.5 million, or $3.23
and $3.22 per basic and diluted common share, respectively,
before a non-cash, after-tax charge of $173.9 million, or $3.28
per basic share, recorded in the first quarter related to NSTAR's
investment in RCN Corporation (RCN).  Factors that contributed to
the $3.5 million, or 2%, decline in earnings before the non-cash,
after-tax charge include a decline in firm gas sales (in billions
of British thermal units or BBTU) of 11%, a proposed refund of
$3.9 million to electric customers in conjunction with NSTAR's
service quality plan, the accrual of costs associated with a
pending shutdown of a district energy facility of $5 million and
a decline in the return on equity on the plant investment base of
the Seabrook facility.  Positive factors included a slight
increase in retail kWh sales of 0.6%, a lower regulatory interest
expense adjustment due to a reconciliation filing of deferred
standard offer and default service costs that resulted in
additional interest expense recorded in 2000, a settlement of
revenues due NSTAR from a former Pilgrim Unit customer and a one-
time gain associated with the receipt of equity securities issued
in conjunction with the demutualization of two mutual insurance
companies that provide coverage to NSTAR subsidiaries.  For 2001,
a decrease of approximately 1.9 million average common shares
outstanding that resulted from the repurchase of shares during
2000 had a positive impact on earnings per share of approximately
eleven cents.

As previously disclosed and further discussed in this report,
NSTAR is finalizing the process of converting its joint venture
investment in RCN into shares of RCN common stock.  NSTAR's
investment in RCN includes 4.1 million common shares that it
currently holds and 7.5 million common shares that it expects to
receive for its remaining interest in the joint venture.
Consistent with the performance of the telecommunications sector
as a whole, the market value of RCN's common shares decreased
significantly during the latter part of 2000 and continued in
2001.  As a result, NSTAR recognized an impairment of its
investment in RCN in the first quarter of 2001.  NSTAR
determined, in the first quarter of 2001, that this decline in
market value was "other-than-temporary" as defined by Statement
of Financial Accounting Standards (SFAS) No. 115, "Accounting for
Certain Investments in Debt and Equity Securities."

Operating Revenues
<TABLE>
<CAPTION>
Operating revenues for 2001 increased 19% from 2000 as follows:
<S>                                            <C>
  (in thousands)
  Retail electric revenues                       $ 432,058
  Wholesale electric revenues                        8,969
  Gas sales revenues                                19,725
  Other revenues                                    38,322
    Increase in operating revenues               $ 499,074
                                                 =========
</TABLE>
Retail electric revenues were $2,497.5 million in 2001 compared
to $2,065.4 million in 2000, an increase of $432.1 million, or
21%.  The change in retail revenues includes a 0.6% increase in
retail kWh sales, higher rates implemented in January and July
2001 for standard offer and default services, which increased
retail revenues by $250.2 million and $257.5 million,
respectively and the absence in 2001 of a $30.8 million fuel
charge refund to customers in 2000.  These revenue increases were
partially offset by lower transition revenues of $88.1 million
due to a decline in rates, a decline in transmission revenues of
$6.5 million and a decline of $1.9 million for demand-side
management and other revenues.  The increase in NSTAR's retail
revenues related to standard offer and default services are fully
reconciled to the costs incurred and have no impact on net
income.  The number of retail customers increased in 2001 to
1,086,000 from 1,079,000 customers and represents a growth rate
of 0.7%.  The customer growth rate in 2002 is projected to be an
additional 0.7%.

The 0.6% increase in 2001 retail kWh sales primarily reflects
growth in the residential and commercial sectors of 1.1% and
1.7%, respectively.  NSTAR Electric's sales to residential and
commercial customers were approximately 30% and 59%,
respectively, of its total retail sales mix for 2001 and provided
41% and 51% of distribution revenue, respectively.  Industrial
sector sales declined 7.8% due primarily to a slowdown in
economic conditions that resulted from reduced production or
facility closings.  The industrial sector comprises approximately
10% of NSTAR's energy sales and 6% of distribution revenue.

NSTAR forecasts its electric and gas sales based on normal
weather conditions.  Forecasted results may differ from those
projected due to actual weather conditions above or below these
normal weather levels.

Weather conditions greatly impact the change in electric and, to
a larger extent, gas sales and revenues in NSTAR's service area.
The summer period of 2001 was significantly warmer than the same
period in 2000, and this abnormal pattern continued into the
fourth quarter heating season of 2001 with above normal
temperatures.  Below is comparative information on cooling and
heating degree days in 2001 and 2000 and the number of degree
days in a "normal" year as represented by a 30-year average.
<TABLE>
<CAPTION>
<S>                                     <C>        <C>     <C>
                                                             30-Year
                                           2001       2000   Average

Cooling degree days                          822       588     678
  Percentage change from prior year        39.8%    (34.0)%
  Percentage change from 30-year average   21.2%    (13.3)%
Heating degree days                        5,637      6,147  5,939
  Percentage change from prior year       (8.3)%      11.7%
  Percentage change from 30-year average  (5.1)%       3.5%
</TABLE>

Wholesale electric revenues were $86.9 million in 2001 compared
to $77.9 million in 2000, an increase of $9 million, or 12%.
This increase in wholesale revenues primarily reflects increased
demand from a public transit authority and municipal contracts.
In 2002, wholesale electric sales are forecasted to decrease due
to the expiration of contracts with several municipalities.  The
expiration of these contracts is not expected to impact NSTAR's
consolidated earnings.

Gas sales revenues were $388.4 million in 2001 compared to $368.7
million in 2000, an increase of $19.7 million, or 5%.  The
increase in revenues is primarily attributable to the recovery of
prior period gas costs, partially offset by an 11% decline in
firm sales and transportation due to the economic slowdown in the
commercial and industrial sectors.  NSTAR Gas' sales are
positively impacted by colder weather because a substantial
portion of its customer base uses natural gas for space heating
purposes.  Conversely, warmer weather conditions have a negative
impact on gas sales.  This was the case during the fourth quarter
of 2001 when firm gas sales declined 31.2% from the prior year
and were significantly impacted by the 24.6% decline in heating-
degree days.

As indicated above, heating degree days in 2001 were 8.3% below
2000 and 5.1% below normal and contributed to the decrease in
firm sales and transportation.  NSTAR Gas' firm BBTU sales to
residential and commercial customers were approximately 65% and
27%, respectively, of total 2001 firm sales.  The number of firm
customers increased in 2001 to 246,000 customers and represents a
growth rate of 0.8%.  The customer growth rate in 2002 is
projected to be an additional 1.25%.

Other revenues were $219.1 million in 2001 compared to $180.8
million in 2000, an increase of $38.3 million, or 21%.  This
change reflects higher New England Power Pool related
transmission revenues and higher revenues realized from district
energy operations.

Operating Expenses

Purchased power and cost of gas sold expense was $1,913 million
in 2001, compared to $1,385.7 million in 2000, an increase of
$527.3 million, or 38%. The purchased power component of these
costs was $1,673.5 million in 2001 compared to $1,172.9 million
in 2000, an increase of $500.6 million, or 43%.  The increase in
purchased power expense reflects the impact of the recognition of
previously deferred standard offer and default service supply
costs resulting from collection of these costs in 2001.  NSTAR
Electric adjusts its electric rates to collect the costs related
to energy supply from customers on a fully reconciling basis.
Due to the rate adjustment mechanisms, changes in the amount of
energy supply expense have no impact on earnings.  Also impacting
this increase were increases in purchased power requirements due
to a 0.6% increase in retail sales and a 2.2% increase in
wholesale sales, partially offset by lower costs that reflect the
prices of natural gas and oil.  Further contributing to the
increase in total expense is the cost of gas sold, representing
NSTAR Gas' supply expense, which was $239.5 million for 2001
compared to $212.8 million in 2000, an increase of $26.7 million,
or 13%, due primarily to the higher gas supply costs in 2001.
These expenses are also fully reconciled to the current level of
revenues collected.

Operations and maintenance expense was $417.1 million in 2001
compared to $415.8 million in 2000, an increase of $1.3 million,
or 0.3%.  This slight increase reflects higher electric
distribution weather-related maintenance costs related to a major
late-winter storm in March and severe summer weather during 2001
and higher maintenance costs incurred in connection with NSTAR's
unregulated subsidiary activities.  Other factors that increased
expenses were higher bad debt expense primarily due to the
increased sales and higher costs related to post-retirement and
other benefits.  Offsetting this increase was the absence of non-
recurring computer system implementations costs incurred during
2000.

In 2002, operations and maintenance expense is forecasted to
increase significantly to support the utility System Improvement
Program of $11 million and increased pension costs.  NSTAR has
forecasted that pension costs will increase by approximately $20
million for 2002 as compared to 2001.  This is due to the
downturn in equity markets, which have reduced the value of
NSTAR's pension investments and the impact of lower interest
rates.  This expected level of expense could vary due to external
factors beyond the Company's control.

Depreciation and amortization expense was $231 million in 2001
compared to $238.6 million in 2000, a decrease of $7.6 million,
or 3%.  The decrease primarily reflects the buy-down of the
Seabrook investment in November 2000 utilizing the majority of
the proceeds from the sale of Canal's generating units.  Further
contributing to this decrease was the write-down of the remaining
assets of a district energy facility in 2000 and decreased
amortization of software-related costs, partially offset by a
slightly higher level of system-wide depreciable plant-in-
service.

Demand side management (DSM) and renewable energy programs
expense was $70.1 million in 2001 compared to $78.8 million in
2000, a decrease of $8.7 million, or 11%, primarily due to timing
of DSM expense.  These costs are in accordance with program
guidelines established by regulators and are collected from
customers on a fully reconciling basis.  In addition, NSTAR earns
incentive amounts in return for increased customer participation.

Property and other taxes were $96.5 million in 2001 compared to
$82.1 million in 2000, an increase of $14.4 million, or 18%.  The
increase was due to the fact that during 2000, Boston Edison was
reimbursed for the majority of its payments in lieu of property
taxes to the Town of Plymouth by Entergy.  Entergy purchased the
Pilgrim Unit from Boston Edison in 1999.

Income taxes from operations were $113.4 million in 2001 compared
to $117.4 million in 2000, a decrease of $4 million, or 3%,
reflecting the impact of lower pre-tax operating income.

Other Income (Deductions), net

Other deductions were $169 million in 2001 compared to income of
$12.1 million in 2000, a net decrease in income of $181.1 million
primarily attributable to the aforementioned non-cash, after-tax
charge related to the carrying value of the RCN investment.  This
is discussed further in this section under the caption "RCN Joint
Venture and Investment Conversion."

The decrease in other income, net for 2001 reflects the result of
income items recognized in 2000 related to a gain of $3.4 million
from the sale of land by a non-utility subsidiary, $4.4 million
received from a third party related to the Pilgrim wholesale
contract buyout and interest income on funds held by EIS of $7.6
million (EIS interest income in 2001 was $743,000 and these
amounts were offset entirely with interest charges).  Offsetting
these gains in 2000 was the impact of NSTAR COM RCN joint venture
losses of $5.6 million and in 2001, $4.5 million of income
associated with the receipt of common stock in connection with
the demutualization of two insurance companies.  These factors
were offset in 2001 by $3.8 million for the accrual of costs
associated with a pending shutdown of an unregulated district
energy facility.

Interest Charges

Interest on long-term debt and transition property securitization
certificates was $158.4 million in 2001 compared to $154.8
million in 2000, an increase of $3.6 million, or 2%.  This change
in long-term interest costs includes $15.3 million that reflects
a full-year of debt outstanding from the issuance of $300 million
and $200 million of NSTAR 8% Notes in February and October of
2000, respectively, offset somewhat by a decrease of $7.6 million
that reflects the retirement of $199 million in Boston Edison
debt and the paydown of other subsidiary company debt of $7.4
million throughout 2000 as compared to retirements and paydowns
in 2001 of $24.3 million and $10.1 million, respectively.  Long-
term debt interest in 2001 also reflects a reduction of
securitization certificates interest of $4 million due to the
partial retirement of this debt.  Securitization interest
represents interest on debt collateralized by the future income
stream associated with the stranded costs of the Pilgrim Unit
divestiture.  These certificates are non-recourse to Boston
Edison.

Interest on short-term and other obligations was $25.3 million in
2001 compared to $55.2 million in 2000, a decrease of $29.9
million, or 54%.  This decrease is primarily due to a
reconciliation adjustment of regulatory deferrals in conjunction
with an MDTE reconciliation that resulted in the recognition of
interest expense in 2000, and the positive impact of
approximately $4 million resulting from lower interest rates that
includes the impact of higher average short-term borrowing levels
from banks.  The increase in borrowing is primarily the result of
financing long-term debt and preferred stock retirements with
short-term borrowing and other working capital requirements.
Further contributing to the lower interest expense in 2001 was an
offset to previously accrued interest expense on Internal Revenue
Service tax matters that were settled in 2001.

2000 versus 1999

Consistent with the application of the purchase method of
accounting, the results for 2000 reflect the results of NSTAR for
a full year while the results for 1999 reflect eight months of
BEC and four months of NSTAR.

Basic and diluted earnings per common share were $3.19 and $3.18,
respectively, in 2000, compared to $2.77 and $2.76, respectively,
in 1999, a 15% increase.  The dilutive impact on earnings of an
additional 4.1 million average common shares outstanding at year-
end 2000 ($0.26 per share) reflects shares issued to transact the
merger in 1999, partially offset by 5 million shares repurchased
in 2000 upon completion of a common share repurchase plan.

Operating Revenues
<TABLE>
<CAPTION>
Operating revenues for 2000 increased 45% from 1999 as follows:
<S>                                             <C>
  (in thousands)
  Retail electric revenues                       $ 514,627
  Wholesale electric revenues                      (30,704)
  Gas sales revenues                               261,585
  Other revenues                                    95,827
    Increase in operating revenues               $ 841,335
                                                 =========
</TABLE>

Retail electric revenues were $2,065.4 million in 2000 compared
to $1,550.8 million in 1999, an increase of $514.6 million, or
33%.  The change in retail revenues reflects a full year of NSTAR
operations, the recognition of mitigation incentive revenue
entitlements for successfully lowering transition charges, the
higher costs of natural gas and oil as a component of purchased
power and the impact of a 25% increase in retail kWh sales
reflecting the addition of COM/Energy.  On a combined pro-forma
basis as if BEC and COM/Energy were NSTAR for the entire year of
1999, retail kWh sales increased 3.3%.  The increase in retail
kWh sales is the result of a strong local economy as indicated by
a 2.2% improvement in the overall Massachusetts employment rate,
new construction and customer growth.  In addition, NSTAR
Electric increased its standard offer and default service rates
in January and December 2000. NSTAR Electric's standard offer
revenues were $616.4 million and $467.7 million in 2000 and 1999,
respectively.  The revenues derived from standard offer and
default services are fully reconciled to the costs incurred and
have no impact on net income.

Wholesale electric revenues were $77.9 million in 2000, compared
to $108.6 million in 1999, a decrease of $30.7 million, or 28%.
This decrease in wholesale revenues primarily reflects the
absence of sales to Pilgrim contract customers due to the sale of
Pilgrim in July 1999.

Gas sales revenues were $368.7 million in 2000 compared to $107.1
million in 1999, an increase of $261.6 million, or 244%.  The
increase represents NSTAR Gas operations for a full year.  In
addition, on a comparable basis, the fourth quarter firm and
transportation BBTU gas sales were higher by 25% due to colder
weather.  Heating degree days for the fourth quarter of 2000
totaled 2,246, 20% above the same period last year and 12%
greater than the normal level of 2,009. On a combined pro-forma
basis as if BEC and COM/Energy were NSTAR for the entire year of
1999, firm gas sales and transportation increased 15%.

Other revenues were $180.8 million in 2000 compared to $84.9
million in 1999, an increase of $95.9 million, or 113%.  This
revenue increase primarily reflects non-utility district heating
and cooling energy sales operations in 2000 and higher
transmission revenues related to refunds to wholesale customers
in 1999 resulting from a FERC-approved settlement with
transmission contract customers.

Operating Expenses

Operating expenses for 2000 include a full year of expenses for
NSTAR, while the level of expenses for 1999 reflect eight months
of BEC Energy and four months of NSTAR.

Purchased power and cost of gas sold expense was $1,385.7 million
in 2000, compared to $794.7 million in 1999, an increase of $591
million, or 74%.  The purchased power component of these costs
was $1,172.9 million in 2000 compared to $736.8 million in 1999,
an increase of $436.1 million, or 59%.  The increase in 2000
primarily reflects a full year of NSTAR operations, an increase
in purchased power requirements due to the sale of Pilgrim in
1999, an overall increase in the cost of wholesale power and
increased requirements resulting from increased kWh sales and
firm gas sales.  NSTAR Electric adjusts its rates to collect the
costs related to fuel and purchased power from customers on a
fully reconciling basis.  Fuel and purchased power expenses
reflect a reduction of $212.7 million in 2000 and $67.3 million
in 1999 related to these rate recovery mechanisms.  Due to the
rate adjustment mechanisms, changes in the amount of purchased
power expense have no impact on earnings.  The cost of gas sold,
representing NSTAR Gas' supply expense, was $212.8 million in
2000 compared to $57.9 million in 1999, an increase of $154.9
million and is also fully reconciled.

Operations and maintenance expense was $415.8 million in 2000
compared to $353.8 million in 1999, an increase of $62 million,
or 18%.  The increase primarily reflects a full year of NSTAR
operations that was partially offset by the absence of $70
million of nuclear power production expenses due to the sale of
Pilgrim.  As a result of the merger, operations and maintenance
cost savings were realized due to reduced staffing levels and
operating efficiencies.  In addition, NSTAR experienced
significantly lower costs for employee pensions and benefits in
2000.

Depreciation and amortization expense was $238.6 million in 2000
compared to $210.3 million in 1999, an increase of $28.3 million,
or 13%.  The increase reflects approximately $23.2 million
resulting from a full year of amortization of goodwill and costs
to achieve related to the merger compared to $8 million in 1999
and approximately $13.4 million related to other amortization and
depreciation for a full year of NSTAR operations and capital
additions.  These increases were partially offset by the sale of
Pilgrim in July 1999.

DSM and renewable energy programs expense was $78.8 million in
2000 compared to $63.4 million in 1999, an increase of $15.4
million, or 24% primarily due to a full year of NSTAR operations.
These costs are in accordance with program guidelines established
by the MDTE and are collected from customers on a fully
reconciling basis and therefore, fluctuations in program costs
have no impact on earnings.  In addition, NSTAR earns incentive
amounts in return for increased customer participation.

Property and other taxes were $82.1 million in 2000 compared to
$77.8 million in 1999, an increase of $4.3 million, or 6%.  The
increase is primarily due to a full year of NSTAR operations
partially offset by lower municipal property taxes primarily
related to the sale of Pilgrim.

Other Income (Deductions), net

Other income, net of taxes was $12.1 million in 2000 compared to
income of $8.1 million in 1999, a net increase in income of $4
million, or 49%.  The increase in income in 2000 reflects
interest income on funds held by EIS of $7.6 million compared to
$2.8 million in the prior year.  These amounts were offset
entirely with interest charges.  Also, 2000 includes a gain of
$3.4 million from the sale of land by a non-utility subsidiary
and $4.4 million received from a third party related to the
Pilgrim wholesale contract buyout.  Offsetting these factors in
2000 was the absence of $20.8 million related to the 1999
recognition of previously deferred investment tax credits
associated with the Pilgrim Unit that was sold in 1999.  Also in
2000, the change in other income reflected significantly lower
NSTAR Com RCN joint venture losses which amounted to $5.6 million
in 2000 that reflected NSTAR Com's decreased ownership interest
compared to $16.2 million in 1999.

Interest Charges

Interest on long-term debt and transition property securitization
certificates was $154.8 million in 2000 compared to $104.6
million in 1999, an increase of $50.2 million, or 48%.  The
increase reflects $25.1 million of interest related to transition
property securitization certificates issued in July 1999, $24.7
million related to the $500 million 8% Notes issued in February
2000 ($300 million) and in October 2000 ($200 million) and a full
year of NSTAR operations.  These increases were partially offset
by approximately $12.3 million in reductions related to the
retirements as described in this section under the caption
"Liquidity and Capital Resources."

Interest on short-term and other obligations was $55.2 million in
2000 compared to $22.9 million in 1999, an increase of $32.3
million, or 141%.  This increase is directly related to increases
in short-term borrowings, primarily the result of increases of
approximately $147 million in the unrecovered costs for standard
offer and default service during 2000 (to a balance of $242.7
million at December 31, 2000).  In addition, 2000 reflects $7.5
million of interest costs associated with additional borrowing
used to finance deferred transition costs and $1.1 million on
deferred gas costs.

Allowance for borrowed funds used during construction (AFUDC)
amounted to $4.6 million in 2000 compared to $2.2 million in
1999, an increase of $2.4 million.  This increase is primarily
related to capitalized interest associated with construction of
NSTAR's new office facility located in Westwood, Massachusetts
and the impact of a full year of NSTAR operations.

Liquidity and Capital Resources

During 2001, 2000 and 1999, internal generation of cash provided
103%, 188% and 174%, respectively, of plant expenditures.
Internally generated funds consist of cash flows from operating
activities, adjusted to exclude changes in working capital and
the payment of dividends.  NSTAR companies supplement internally
generated funds as needed, primarily through the issuance of
short-term commercial paper and bank borrowings.

The capital spending level forecasted for 2002 is $315 million,
which includes approximately $271 million for electric and gas
operations and the balance for other capital requirements of non-
utility ventures.  Also, included in this level of spending is
$54 million of costs associated with NSTAR's System Improvement
Program.  The capital spending level over the following four
years is forecasted to aggregate approximately $737 million.

Management continuously reviews its capital expenditure and
financing programs.  These programs and, therefore, the estimates
included in this Form 10-K are subject to revision due to changes
in regulatory requirements, environmental standards, availability
and cost of capital, interest rates and other assumptions.
<TABLE>
<CAPTION>
NSTAR has long-term debt principal payments, minimum lease
commitments, electric capacity charge obligations under contracts
and natural gas contractual agreements at December 31, 2001, for
each of the years presented below:
<S>                          <C>       <C>     <C>      <C>    <C>
  (in millions)                 2002     2003    2004     2005   2006
  Long-term debt               $   38   $  173  $   10   $   9  $   29
  Transition property
   securitization certificates     70       68      69      69      69
  Leases                           23       19      18      17      15
  Electric capacity obligations   177      166     168     171     173
  Gas contractual obligations      52       49      40      39      38
                               $  360   $  475  $  305   $ 305  $  324
                               ======   ======  ======   =====  ======
 </TABLE>

In 2001, long-term debt financing activities included redemptions
of securitization certificates of $62 million, redemption of all
500,000 shares outstanding of Boston Edison's Cumulative
Preferred Stock, 8% Series, at the mandatory redemption price of
$100 per share, the early redemption of $24.3 million 9.375%
debentures, and other scheduled sinking fund payments.  There
were no new long-term debt issuances in 2001.  In February and
October 2000, NSTAR issued $300 million and $200 million,
respectively, 8% notes, due February 2010, of long-term debt
related to its $500 million shelf registration.  Proceeds from
these issues were used to pay down short-term borrowings.  These
increases in long-term debt were partially offset in 2000 by $206
million in long-term debt retirements, that included Boston
Edison debenture redemptions of $65 million (6.8% Series) in
February, $34 million (9.875% Series) in June and $100 million
(6.05% Series) in August.

NSTAR has a $450 million revolving credit agreement with a group
of banks effective through November 2002.  At December 31, 2001
and 2000, there were no amounts outstanding under this revolving
credit agreement.  This arrangement serves as back-up to NSTAR's
$450 million commercial paper program that, at December 31, 2001
and 2000, had $315.5 million and $252 million outstanding,
respectively, under its commercial paper program.  NSTAR
anticipates renewing its revolving credit agreement under similar
terms.

Boston Edison has approval from the FERC to issue up to $350
million of short-term debt.  Boston Edison has a $300 million
revolving credit agreement with a group of banks effective
through December 2002.  At December 31, 2001 and 2000, there were
no amounts outstanding under this revolving credit agreement.
This arrangement serves as back-up to Boston Edison's $300
million commercial paper program that, at December 31, 2001 and
2000, had outstanding balances of $191.5 million and $96.5
million, respectively.  Separately, Boston Edison, effective July
20, 2001, has an additional $50 million line of credit with no
outstanding amounts at December 31, 2001.

Boston Edison has approval from the MDTE to issue from time to
time up to $500 million of long-term debt securities through
2002.  In connection with this, on February 20, 2001, Boston
Edison filed a registration statement on Form S-3 with the SEC,
using a shelf registration process, to issue up to $500 million
in debt securities.  The SEC declared the registration statement
effective on February 28, 2001.  When issued, Boston Edison will
use the proceeds to pay at maturity long-term debt and equity
securities, refinance short-term debt and for other corporate
purposes.  No issuance of debt securities were made during 2001
under this authorization.

In addition, ComElectric, Cambridge Electric and NSTAR Gas,
collectively, have $190 million available under several lines of
credit.  Approximately $118 million and $120 million was
outstanding under these lines of credit at December 31, 2001 and
2000, respectively.  ComElectric, Cambridge Electric and Canal
have approval from FERC to issue short-term debt with amounts
ranging from $60 million to $100 million.

In April 1998, BEC announced a common share repurchase program
under which it would repurchase up to four million of its common
shares.  NSTAR assumed this program effective as of the merger
date and completed it in October 1999.  Four million shares were
repurchased at a total cost of approximately $157 million.  NSTAR
subsequently announced a second common share repurchase program,
which began in November 1999, of $300 million that was completed
in September 2000 with the repurchase of approximately 7.2
million shares.

In July 1999, BEC Funding LLC, a wholly owned consolidated
special-purpose subsidiary (SPS) of Boston Edison, closed the
sale of $725 million of notes to a special purpose trust created
by two Massachusetts state agencies.  The trust then concurrently
closed the sale of $725 million of electric rate reduction
certificates to the public.  A portion of the transition charge
assessed to Boston Edison's retail customers, as permitted under
the Restructuring Act and authorized by the MDTE, secures the
certificates held by BEC Funding.  The certificates were issued
in five separate classes with variable payment periods ranging
from approximately one to ten years and bearing fixed interest
rates ranging from 5.99% to 7.03%.  The certificates are non-
recourse to Boston Edison.  Net proceeds ($719 million received
by Boston Edison from BEC Funding) were utilized to finance a
portion of the stranded costs that are being collected from
customers under Boston Edison's restructuring settlement
agreement.  Boston Edison will collect a portion of the
transition charge on behalf of BEC Funding and remit the proceeds
to the SPS.  Boston Edison used a portion of the proceeds
received from the financing to fund a portion of the nuclear
decommissioning fund transferred to Entergy as part of the sale
of the Pilgrim generating station.  Boston Edison used the
remaining proceeds to reduce its capitalization and for general
corporate purposes.

NSTAR's goal is to maintain a capital structure that preserves an
appropriate balance between debt and equity.  Management believes
its liquidity and capital resources are sufficient to meet its
current and projected requirements.

Performance Assurances and Financial Guarantees

NSTAR Electric has entered into a series of purchased power
agreements to meet its default service supply obligations and its
remaining unmet standard offer supply obligations through
December 31, 2002.  NSTAR Electric is completely recovering all
of the payments it is making to suppliers and has financial and
performance assurances and financial guarantees in place with
those suppliers to protect NSTAR Electric from risk in the
unlikely event any of its suppliers encounter financial
difficulties or fail to maintain an investment grade credit
rating.  In connection with certain of these agreements, should,
in the unlikely event, an individual NSTAR Electric distribution
company receive a credit rating below investment grade, that
company potentially could be required to obtain certain financial
commitments, including but not limited to, letters of credit.

Preferred Stock Dividends and Redemptions

Preferred dividends of Boston Edison were approximately $5.6
million in 2001 and $6 million in both 2000 and 1999.  Boston
Edison redeemed all 500,000 shares outstanding of its Cumulative
Preferred Stock, 8% Series, at the mandatory redemption price of
$100 per share, plus accrued dividends from November 1, 2001 to
December 1, 2001.  Effective December 1, 2001, the dividends on
this series ceased.

Other Investments

In the second quarter of 2001, NSTAR recorded $4.5 million as
Other income for equity securities it received in connection with
the demutualization of John Hancock Mutual Life Insurance Company
and MetLife, Inc.  NSTAR and its subsidiaries, as policyholders,
received an appropriate distribution of common stock of each
company.  These securities are currently available for sale and
are included in Other investments on the accompanying
Consolidated Balance Sheets.  The value of these common shares
was adjusted to reflect market values as of December 31, 2001.
The unrealized gain or loss associated with these shares will
fluctuate due to changes in current market values and is
reflected, net of applicable income taxes, as a component of
Comprehensive income (loss) on the accompanying Consolidated
Statements of Comprehensive Income (Loss).  The cumulative
increase or decrease in fair value of these shares as of December
31, 2001 is reflected as a component of Accumulated other
comprehensive income (loss) on the accompanying Consolidated
Balance Sheets.

New Accounting Principles

In June 2001, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standard (SFAS) No. 142,
"Goodwill and Other Intangible Assets" (SFAS 142).  This
Statement, which is effective for NSTAR in the first quarter of
2002, establishes accounting and reporting standards for acquired
goodwill and other indefinite lived intangible assets.  It
prohibits entities from continuing amortization of these assets.
Instead, goodwill and other intangible assets will be subject to
review for impairment.  However, in accordance with paragraph
(d)8 of SFAS 142 and revised paragraph 30 of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation,"
NSTAR plans to continue amortization of this asset over its
estimated regulatory recovery period.  NSTAR has determined that
its unique regulatory rate structure, resulting from the merger
and approved by the MDTE on July 27, 1999, requires continued
amortization of goodwill.  A significant element of this rate
plan includes recovery of the acquisition premium over 40 years
and provides for the reasonable assurance of the existence of a
regulatory asset.  NSTAR will determine the appropriate balance
sheet classification of this asset once adopted.  Management will
continue to review its determination of SFAS 142.

On July 5, 2001, the FASB issued SFAS No. 143, "Accounting for
Asset Retirement Obligations" (SFAS 143).  This Statement, which
is effective for fiscal years beginning after June 15, 2002,
establishes accounting and reporting for obligations associated
with the retirement of tangible long-lived assets and the
associated asset retirement costs.  It applies to legal
obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development
and/or the normal operation of a long-lived asset, except for
certain obligations of lessees.  This standard requires entities
to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred.  When the
liability is initially recorded, the entity capitalizes the cost
by increasing the carrying amount of the related long-lived
asset.  Over time, the liability is accreted to its present value
each period, and the capitalized cost is depreciated over the
useful life of the related asset.  Upon settlement of the
liability, an entity either settles the obligation for its
recorded amount or incurs a gain or loss upon settlement.
Management is currently assessing the impact of SFAS 143 in light
of its regulatory and accounting requirements.  However, based on
NSTAR's assessment to date, the adoption of SFAS 143 is not
expected to have a material effect on its results of operations,
cash flows, or financial position.

As of January 1, 2001, NSTAR adopted SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities" (SFAS 133), as
amended by SFAS Nos. 137 and 138, and collectively referred to as
SFAS 133.  SFAS 133 established accounting and reporting
standards requiring that every derivative instrument (including
certain derivative instruments embedded in contracts possibly
including fixed-price fuel supply and power contracts) be
recorded on the Consolidated Balance Sheets as either an asset or
liability measured at its fair value.

The management of NSTAR has assessed the impact of the adoption
of SFAS 133.  As part of this assessment, NSTAR formed an
implementation team in 2000 consisting of key individuals from
various operational and financial areas of the organization.  The
primary role of this team was to inventory and determine the
impact of potential contractual arrangements for SFAS 133
application.  The implementation team performed extensive reviews
of critical operating areas of NSTAR and documented its
procedures in applying the requirements of SFAS 133 to NSTAR's
contractual arrangements in effect on January 1, 2001.  NSTAR
continues its assessment on any impact that potentially may
result from FASB revisions and clarifications, including, but not
limited to, FASB Derivative Implementation Group Issue C15, to
SFAS 133.  Based on NSTAR's assessment, the adoption of SFAS 133
has not had a material effect on its results of operations, cash
flows, or financial position.

RCN Joint Venture and Investment Conversion

NSTAR Com is a participant in a telecommunications venture with
RCN Telecom Services, Inc. of Massachusetts, a subsidiary of RCN
Corporation (RCN).  NSTAR Com has accounted for its equity
investment in the joint venture using the equity method of
accounting.  As part of the Joint Venture Agreement, NSTAR Com
has the option to exchange portions of its joint venture interest
for common shares of RCN at specified periods.  To date, NSTAR
Com has received approximately 4.1 million shares of RCN common
shares from two prior exchanges of its joint venture interest.

On April 6, 2000, NSTAR Com issued its third and final notice to
exchange substantially all of its remaining interest in the joint
venture into common shares of RCN.  Effective with the third
notice, NSTAR Com's profit and loss sharing ratio was reduced.
During 2000, NSTAR Com recognized $5.6 million in equity losses
from the joint venture.

On October 18, 2000, NSTAR Com and RCN signed an agreement in
principle to amend the Joint Venture Agreement.  Among other
items, this proposal settled the number of shares to be received
for the third conversion of NSTAR Com's remaining equity
investment at 7.5 million shares.  After extensive discussions
and negotiations, NSTAR Com is finalizing revisions to this
agreement and management anticipates having a definitive amended
Joint Venture Agreement in 2002.

As previously disclosed, management continues to evaluate the
carrying value of its entire investment in RCN.  Consistent with
the performance of the telecommunications sector as a whole, the
market value of RCN's common shares decreased significantly
during the latter part of 2000 and continued in 2001.  As a
result, in the first quarter of 2001, management determined that
this decline in market value was "other-than-temporary" in
accordance with the SFAS No. 115, "Accounting for Certain
Investments in Debt and Equity Securities."  The market value of
RCN common shares has continued to decline in the early part of
2002.  Management cannot determine whether this trend will
continue or if or when this sector or RCN's common share value
will recover.  However, should this trend continue for a period
of six months or longer, NSTAR may be required to recognize an
additional non-cash impairment charge in 2002.  Should an
impairment charge be necessary, it is reasonably possible that
this could have a material adverse effect on NSTAR's result of
operations.

Also, during the first quarter of 2001, the status of the
amendment to the Joint Venture Agreement with RCN regarding the
7.5 million shares led management to determine that its
investment in the joint venture was also impaired based on future
market expectations for RCN common shares related to this
investment.

As a result, NSTAR Com, recognized an impairment of its entire
investment in RCN in the first quarter of 2001.  This write-down
resulted in a non-cash, after-tax charge of $173.9 million that
is reported on the accompanying Consolidated Statements of Income
as "Write-down of RCN investment, net."

The RCN shares received, as well as the remaining interest in the
joint venture related to the pending 7.5 million shares, are
included in Other investments on the accompanying Consolidated
Balance Sheets at their estimated fair value of approximately
$40.1 million at December 31, 2001.  The fair value of the shares
currently held may increase or decrease, at any time, as a result
of changes in the market value of RCN common shares.  As of
December 31, 2001 and 2000, the market values of these shares
were $2.93 and $6.31, respectively.  The unrealized gain or loss
associated with shares currently held will fluctuate due to the
changes in fair value of these shares during each period and is
reflected, net of associated income taxes, as a component of
Other comprehensive income (loss), net on the accompanying
Consolidated Statements of Comprehensive Income (Loss).  The
cumulative increase or decrease in fair value of these shares as
of December 31, 2001 reflects the change since the write-down of
these shares as a component of Accumulated other comprehensive
income (loss) on the accompanying Consolidated Balance Sheets.
Management will continue to evaluate the carrying value of its
investment in RCN for declines that are considered other than
temporary.

At December 31, 2001 and 2000, NSTAR Com had $2.6 million and
$47.9 million, respectively, in accounts receivable due from the
joint venture.  Amounts due are primarily the result of
construction performed by NSTAR Com on behalf of the joint
venture.

Contingencies

Environmental Matters

NSTAR's subsidiaries are involved in 26 state-regulated
properties ("Massachusetts Contingency Plan, or "MCP" sites")
where oil or other hazardous materials were previously spilled or
released.  The NSTAR subsidiaries are required to clean up or
otherwise remediate these properties in accordance with specific
state regulations.  There are uncertainties associated with the
remediation costs due to the final selection of the specific
cleanup technology and the particular characteristics of the
different sites.  In addition to the MCP sites, NSTAR
subsidiaries also face possible liability as a potentially
responsible party (PRP) in the cleanup of eight multi-party
hazardous waste sites in Massachusetts and other states where one
or more NSTAR subsidiaries are 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 $5.8 million
and $7 million are included as liabilities in the accompanying
Consolidated Balance Sheets at December 31, 2001 and 2000,
respectively, related to the non-recoverable portion of these
cleanup liabilities.  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 an
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 over a 7-year period without carrying
costs.  As of December 31, 2001, NSTAR Gas has recorded a
liability of $6.7 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 and as either additional sites are
identified or NSTAR's responsibilities for such sites are
resolved.  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 1998 MDTE order approving the Boston Edison electric
restructuring settlement agreement was appealed by certain
parties to the Massachusetts Supreme Judicial Court.  One appeal
remains pending.  However, there has to date been no briefing,
hearing or other action taken with respect to this proceeding.
However, if an unfavorable outcome were to occur, there could be
a material adverse impact on business operations, the
consolidated financial position, cash flows and the results of
operations for a reporting period.

The 1999 MDTE order approving the rate plan associated with the
merger of BEC and COM/Energy was appealed by certain parties to
the Massachusetts Supreme Judicial Court.  The appeals of the AG
and a separate group that consists of The Energy Consortium and
Harvard University remain pending.  In October 2001, the MDTE
certified the record of the case to the court; however, there has
to date been no briefing, hearing or other action taken with
respect to this proceeding.  If an unfavorable outcome were to
occur, there could be a material adverse impact on business
operations, the consolidated financial position, cash flows and
the results of operations for a reporting period.




Employees and Employee Relations

As of December 31, 2001, NSTAR had approximately 3,300 full-time
employees, including approximately 2,300 or 70% of whom are
represented by two collective bargaining units covered by
separate contracts.  Effective in May 2001, all employees are
employed by NSTAR Electric & Gas Corporation (NSTAR Electric &
Gas).  As of December 2000, the management of NSTAR's utility
subsidiaries and eight separate utility union bargaining units
reached an agreement to merge most of the unionized workforce,
effective January 1, 2001, into Local 369 of the Utility Workers
Union of America, AFL-CIO.  The new agreement results in a single
bargaining unit of approximately 2,000 NSTAR Electric & Gas
employees with a five-year contract expiring May 15, 2005 that
replaced seven separate and widely diverse agreements.

A collective bargaining unit contract representing approximately
300 NSTAR Electric & Gas employees expires March 31, 2002.  On
March 24, 2002, Local 12004, United Steelworkers of America, AFL-
CIO-CLC ratified a new contract that expires on March 31, 2006.

Management believes it has satisfactory employee relations with a
significant majority of its employees.

Interest Rate Risk

NSTAR is exposed to changes in interest rates primarily based on
levels of short-term debt outstanding.  The weighted average
interest rates for long-term indebtedness were 7.50% in both 2001
and 2000.  The weighted average interest rate for mandatory
redeemable cumulative preferred stock was 8% in 2000.  Carrying
amounts and fair values of mandatory redeemable cumulative
preferred stock and long-term indebtedness (excluding notes
payable) as of December 31, 2001 and 2000 were as follows:
<TABLE>
<CAPTION>
<S>                     <C>           <C>        <C>        <C>
                                   2001                     2000
                          Carrying       Fair      Carrying       Fair
  (in thousands)           Amount       Value       Amount       Value
  Mandatory redeemable
  cumulative
  preferred stock        $        -   $     -    $   49,519  $   50,890
  Long-term indebtedness $1,970,451   $2,076,190 $2,070,180  $2,090,290
   (including current
     maturities)
</TABLE>

The mandatory redeemable cumulative preferred stock was redeemed
in total on December 3, 2001.

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.  Customers have the option
of continuing to buy power from the retail electric distribution
businesses at standard offer prices through 2004.  The cost of
providing standard offer service includes fuel and purchased
power costs.  Default service is the electricity that is supplied
by the local distribution company when a customer is not
receiving power from standard offer service.  The market prices
for standard offer and default service will fluctuate based on
the average market price for power.  Amounts collected through
standard offer and default service are recovered on a fully
reconciling basis.

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
<TABLE>
<CAPTION>
                              NSTAR
                Consolidated Statements of Income
<S>                                   <C>         <C>         <C>
                                              Years ended December 31,
                                             2001        2000      1999
                                     (in thousands, except earnings per share)

Operating revenues                      $3,191,836  $2,692,762  $1,851,427
Operating expenses:
  Purchased power and cost of gas sold   1,912,991   1,385,724     794,748
  Operations and maintenance               417,141     415,806     353,768
  Depreciation and amortization            230,949     238,608     210,306
  Demand side management and
    renewable energy programs               70,093      78,774      63,425
  Property and other taxes                  96,489      82,136      77,761
  Income taxes                             113,412     117,420      87,721
      Total operating expenses           2,841,075   2,318,468   1,587,729

Operating income                           350,761     374,294     263,698

Other (deductions) income:
  Write-down of RCN investment, net       (173,944)          -           -
  Other income, net                          4,972      12,061       8,078
      Total other (deductions)income, net (168,972)     12,061       8,078

Operating and other income                 181,789     386,355     271,776

Interest charges:
  Long-term debt                           116,939     109,299      84,196
  Transition property securitization
    certificates                            41,475      45,505      20,408
  Short-term and other                      25,268      55,182      22,873
  Allowance for borrowed funds used
    during construction (AFUDC)             (5,094)     (4,593)     (2,164)

      Total interest charges               178,588     205,393     125,313

Net income                                   3,201     180,962     146,463
Preferred stock dividends of subsidiary      5,627       5,960       5,960
Earnings (loss) available for common
  shareholders                          $   (2,426)  $ 175,002  $  140,503
                                        ==========   =========  ==========
Weighted average common shares outstanding:
  Basic                                     53,033      54,887      50,796
  Diluted                                   53,216      55,045      50,921
Earnings (loss) per common share:
  Basic                                 $    (0.05)  $    3.19  $     2.77
  Diluted                               $    (0.05)  $    3.18  $     2.76

The accompanying notes are an integral part of the consolidated
financial statements.
</TABLE>
<TABLE>
<CAPTION>
                              NSTAR
     Consolidated Statements of Comprehensive Income (Loss)
<S>                                    <C>          <C>        <C>
                                              Years ended December 31,
                                             2001        2000        1999
                                                 (in thousands)

Net income                               $   3,201   $  180,962  $  146,463
Other comprehensive income (loss), net:
  Changes in unrealized gain (loss) on
    investments                             34,901      (53,255)     20,115
  Non-qualified benefit obligation           1,040       (1,004)          -
Comprehensive income                     $  39,106   $  126,703  $  166,578
                                         =========   ==========  ==========



The accompanying notes are an integral part of the consolidated
financial statements.
</TABLE>
<TABLE>
<CAPTION>
                              NSTAR
          Consolidated Statements of Retained Earnings
<S>                                    <C>        <C>         <C>
                                              Years ended December 31,
                                            2001         2000        1999
                                                    (in thousands)

Balance at the beginning of the year   $  446,587   $  389,989  $  360,509
Add:
  Net income                                3,201      180,962     146,463
    Subtotal                              449,788      570,951     506,972
Deduct (add):
Dividends declared:
  Common shares                           110,042      109,315     103,099
  Preferred stock                           5,627        5,960       5,960
    Subtotal                              115,669      115,275     109,059
Provision for preferred stock redemption
  and other                                   (19)         239         239
Common share repurchase programs                -        8,850       7,685
Balance at the end of the year         $  334,138   $  446,587  $  389,989
                                       ==========   ==========  ==========


The accompanying notes are an integral part of the consolidated
financial statements.
</TABLE>

<TABLE>
<CAPTION>
                              NSTAR
                   Consolidated Balance Sheets
<S>                                    <C>            <C>          <C>         <C>
                                                          December 31,
                                                         (in thousands)
                                                   2001                      2000
Assets
Utility plant in service, at
  original cost                          $3,853,295                  $3,699,475
  Less: accumulated depreciation          1,300,868      $2,552,427   1,226,986  $2,472,489
Construction work in progress                                72,957                  48,318
  Net utility plant                                       2,625,384               2,520,807
Non-utility property, net                                   106,007                 105,827
Goodwill                                                    463,626                 475,877
Equity investments (Yankees and Hydro-Quebec)                22,560                  25,791
Other investments                                            73,104                 170,829
Current assets:
  Cash and cash equivalents                 11,655                       21,873
  Restricted cash                           22,966                       22,152
  Accounts receivable, net of allowance of
   $29,763 and $28,309 in 2001 and 2000,
    respectively                           485,687                      454,499
  Accrued unbilled revenues                 51,061                      101,732
  Fuel, materials and supplies, at
    average cost                            53,276                       44,659
  Other                                     33,599          658,244      32,447     677,362
Deferred debits:
  Regulatory assets                                       1,026,241               1,274,790
  Prepaid pension expense                                   218,713                 149,890
  Other                                                     134,312                 146,542

    Total assets                                         $5,328,191              $5,547,715
                                                         ==========              ==========
Capitalization and Liabilities
Common equity                                            $1,260,835              $1,376,369
Accumulated other comprehensive income (loss)                 1,761                 (34,144)
Cumulative non-mandatory redeemable preferred
  stock of subsidiary                                        43,000                  43,000
Long-term debt                                            1,377,899               1,440,431
Transition property securitization certificates             513,904                 584,130
Current liabilities:
  Long-term debt and preferred stock    $   37,676                   $   58,695
  Transition property securitization
    certificates                            40,972                       36,443
  Notes payable                            624,847                      468,347
  Deferred taxes                            41,985                       94,420
  Accounts payable                         209,821                      275,778
  Accrued interest                          29,224                       31,405
  Dividends payable                         28,434                       28,305
  Other                                    250,540       1,263,499      314,688   1,308,801
Deferred credits:
  Accumulated deferred income taxes                        616,743                  572,124
  Accumulated deferred investment tax credits               37,877                   39,960
  Power contracts                                           53,041                   61,131
  Other                                                    159,632                  156,633

Commitments and contingencies

    Total capitalization and liabilities                $5,328,191               $5,547,715
                                                        ==========               ==========


The accompanying notes are an integral part of the consolidated
financial statements.
</TABLE>

<TABLE>
<CAPTION>
                              NSTAR
              Consolidated Statements of Cash Flows
<S>                                           <C>        <C>       <C>
                                                  Years ended December 31,
                                                      (in thousands)
                                                   2001       2000       1999
Operating activities:
  Net income                                   $  3,201    $180,962   $146,463

  Adjustments to reconcile net income to
   net cash provided by operating activities:
    Depreciation and amortization               230,949     240,576    212,880
    Deferred income taxes and investment
      tax credits                               (29,250)     54,835     88,174
    Loss on write-down of RCN investment        168,376           -          -
    Demutualization income                       (4,537)          -          -
    Allowance for borrowed funds used
      during construction                        (5,094)     (4,593)    (2,164)
    Power contract buy out                      (12,741)    (11,679)   (65,781)
  Net changes (net of effect of acquisition) in:
    Accounts receivable and accrued unbilled
      revenues                                   19,483    (124,417)   (96,909)
    Fuel, materials and supplies, at average
      cost                                       (8,617)      4,097     (2,192)
    Accounts payable                            (53,216)     93,520     19,469
    Other current assets and liabilities       (119,040)   (196,483)   (87,032)
  Other, net                                    135,673     (67,168)   (29,548)

Net cash provided by operating activities       325,187     169,650    183,360

Investing activities:
  Plant expenditures (excluding AFUDC)         (228,704)   (182,709)  (159,295)
  Costs of nuclear divestiture, net                   -           -    (87,248)
  Nuclear fuel expenditures                      (1,163)     (1,597)   (16,117)
  Other investments                               3,231     (53,843)   (82,403)
  Payment for cost of acquisition, net of
    cash acquired                                     -           -   (296,262)

Net cash used in investing activities          (226,636)   (238,149)  (641,325)
Financing activities:
  Redemptions:
    Preferred stock                             (50,000)          -          -
    Long-term debt                              (99,728)   (257,853)  (255,361)
  Financing costs                                     -      (2,100)         -
  Proceeds from transition property
    Securitization                                    -           -    725,000
  Issuances/(repurchases):
    Common shares                                     -    (212,611)  (189,715)
    Long-term debt                                    -     500,000     20,000
  Net change in notes payable                   156,500      10,347    340,550
  Dividends paid                               (115,541)   (116,010)  (103,036)
Net cash (used in) provided by financing
  activities                                   (108,769)    (78,227)   537,438
Net (decrease) increase in cash and cash
  equivalents                                   (10,218)   (146,726)    79,473
Cash and cash equivalents at the
beginning of the year                            21,873     168,599     89,126

Cash and cash equivalents at the end of
the year                                       $ 11,655    $ 21,873   $168,599
                                               ========    ========   ========

Supplemental disclosures of cash flow
  information:                                    2001        2000       1999
Cash paid during the year for:
  Interest, net of amounts capitalized         $177,239   $ 166,072   $125,840
  Income taxes (refund)                        $198,326   $ (11,441)  $ 36,092
Supplemental disclosure of investing activity:
  Investment in common shares                  $  4,537           -          -
  Common shares issued for acquisition
    of COM/Energy                                     -           -     20,251


The accompanying notes are an integral part of the consolidated financial statements.

</TABLE>

Notes to Consolidated Financial Statements

Note A. Summary of Significant Accounting Policies

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 246,000 gas
customers in 51 communities.  NSTAR was created through the
merger of BEC Energy (BEC) and Commonwealth Energy System
(COM/Energy) on August 25, 1999 as an exempt public utility
holding company.  NSTAR's retail utility subsidiaries are Boston
Edison Company (Boston Edison), Commonwealth Electric Company
(ComElectric), Cambridge Electric Light Company (Cambridge
Electric) and NSTAR Gas Company (NSTAR Gas).  Its wholesale
electric subsidiary is Canal Electric Company (Canal).  NSTAR's
three retail electric companies operate under the brand name
"NSTAR Electric."  Reference in this report to "NSTAR Electric"
shall mean each of Boston Edison, ComElectric and Cambridge
Electric.  NSTAR's non-utility operations include
telecommunications - NSTAR Communications, Inc. (NSTAR Com),
district heating and cooling operations (Advanced Energy Systems,
Inc. and NSTAR Steam Corporation) and a liquefied natural gas
service company (Hopkinton LNG Corp.).

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 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 the
Financial Accounting Standards Board (FASB) Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation" (SFAS 71).  The
application of SFAS 71 results in differences in the timing of
recognition of certain expenses from that of other businesses and
industries.  The distribution business remains subject to rate-
regulation and continues to meet the criteria for application of
SFAS 71.  Refer to Note D to these Consolidated Financial
Statements for more information on the accounting implications of
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, distribution and
transition revenues for electricity and natural gas delivered to
customers but not yet billed are accrued at the end of each
accounting period.

Revenues for NSTAR's non-utility subsidiaries are recognized when
services are rendered or when the energy is delivered.

4. Utility Plant

Utility plant is stated at original cost of construction.  The
costs of replacements of property units are capitalized.
Maintenance and repairs and replacements of minor items are
expensed as incurred.  The original cost of property retired, net
of salvage value, and the related costs of removal are charged to
accumulated depreciation.  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 for utility and non-utility property were
3.02%, 3.06% and 3.31% in 2001, 2000 and 1999, respectively.
Depreciation of non-utility property is computed on a straight-
line basis over the estimated life of the asset and ranges from 5
to 33 years.

6. Investments - Available for Sale Securities

NSTAR classifies its investment in marketable securities as
available for sale.  These investments include 4.1 million common
shares of RCN Corporation, 148,400 common shares of John Hancock
Financial Services, Inc. and 141,300 common shares of MetLife,
Inc.  NSTAR includes any unrealized gains or losses on these
securities in Accumulated other comprehensive income (loss), net
on the accompanying Consolidated Balance Sheets.

7. Costs Associated with Issuance and Redemption of Debt and
Preferred Stock

Consistent with the recovery in utility rates, discounts,
redemption premiums and related costs associated with the
issuance and redemption of long-term debt and preferred stock are
deferred.  The costs related to long-term debt are recognized as
an addition to interest expense over the life of the original or
replacement debt.  Consistent with an accounting order received
from the FERC, costs related to preferred stock issuances and
redemptions are reflected as a direct reduction to retained
earnings upon redemption or over the average life of the
replacement preferred stock series as applicable.

8. Allowance for Borrowed Funds Used During Construction (AFUDC)

AFUDC represents the estimated costs to finance utility plant
construction. In accordance with regulatory accounting, AFUDC is
included as a cost of utility plant and a reduction of current
interest charges.  Although AFUDC is not a current source of cash
income, the costs are recovered from customers over the service
life of the related plant in the form of increased revenues
collected as a result of higher depreciation expense.  Average
AFUDC rates in 2001, 2000 and 1999 were 4.31%, 6.16%, and 5.82%,
respectively, and represented only the cost of short-term debt
and excludes the impact of capitalized interest. AFUDC also
includes capitalized interest on non-utility plant.

9. Cash, Cash Equivalents and Restricted Cash

Cash, cash equivalents and restricted cash are comprised of
liquid securities with maturities of 90 days or less when
purchased.  Restricted cash primarily represents the net proceeds
from the sale of Canal's generation assets that are required to
be used to reduce the transition costs that otherwise would be
billed to customers.

10. Equity Method of Accounting

NSTAR uses the equity method of accounting for investments in
corporate joint ventures in which it does not have a controlling
interest.  Under this method, it records as income or loss the
proportionate share of the net earnings or losses of the joint
ventures with a corresponding increase or decrease in the
carrying value of the investment.  The investment is reduced as
cash dividends are received.  NSTAR participates in several
corporate joint ventures in which it has investments, principally
its 14.5% equity investment in two companies that own and operate
transmission facilities to import electricity from the Hydro-
Quebec System in Canada, and its equity investments ranging from
2.5% to 14% in three regional nuclear facilities that are
currently being decommissioned and one operating nuclear
generating facility.

11. 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.  Goodwill associated with this acquisition 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 amounts
to approximately $12.2 million annually, while the costs to
achieve (CTA) are being amortized over 10 years and will
initially be approximately $11.1 million annually.  CTA are the
costs incurred to execute the merger including the employee costs
for a voluntary severance program, legal costs, transaction costs
and systems integration costs.  The ultimate amortization of the
CTA will reflect the total actual costs.  Refer to "New
Accounting Principles" under Item 13 of this note, for guidance
on changes in accounting for goodwill.

12. 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.
<TABLE>
<CAPTION>
Regulatory assets consisted of the following:
<S>                                         <C>           <C>
                                                    December 31,
(in thousands)                                    2001         2000
Generation-related regulatory assets, net    $  686,519    $  697,688
Purchased power costs                            45,413       242,663
Costs to achieve                                118,059       119,519
Power contracts                                  53,041        61,131
Income taxes, net                                53,375        55,887
Postretirement benefits costs                    16,965        26,692
Redemption premiums                              12,853        14,403
Other                                            40,016        56,807
  Total regulatory assets                    $1,026,241    $1,274,790
                                             ==========    ==========
</TABLE>

13. New Accounting Principles

In June 2001, FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets" (SFAS 142).  This Statement, which is
effective for NSTAR in the first quarter of 2002, establishes
accounting and reporting standards for acquired goodwill and
other indefinite lived intangible assets.  It prohibits entities
from continuing amortization of these assets.  Instead, goodwill
and other intangible assets will be subject to review for
impairment.  However, in accordance with paragraph (d)8 of SFAS
142 and revised paragraph 30 of SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation," NSTAR plans to continue
amortization of this asset over its estimated regulatory recovery
period. NSTAR has determined that its unique regulatory rate
structure, resulting from the merger and approved by the MDTE on
July 27, 1999, requires continued amortization of goodwill.  A
significant element of this rate plan includes recovery of the
acquisition premium over 40 years and provides for the reasonable
assurance of the existence of a regulatory asset.  NSTAR will
determine the appropriate balance sheet classification of this
asset once adopted.  Management will continue to review its
determination of SFAS 142.

On July 5, 2001, the FASB issued SFAS No. 143, "Accounting for
Asset Retirement Obligations" (SFAS 143).  This Statement, which
is effective for fiscal years beginning after June 15, 2002,
establishes accounting and reporting for obligations associated
with the retirement of tangible long-lived assets and the
associated asset retirement costs.  It applies to legal
obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development
and/or the normal operation of a long-lived asset, except for
certain obligations of lessees.  This standard requires entities
to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred.  When the
liability is initially recorded, the entity capitalizes the cost
by increasing the carrying amount of the related long-lived
asset.  Over time, the liability is accreted to its present value
each period, and the capitalized cost is depreciated over the
useful life of the related asset.  Upon settlement of the
liability, an entity either settles the obligation for its
recorded amount or incurs a gain or loss upon settlement.
Management is currently assessing the impact of SFAS 143 in light
of its regulatory and accounting requirements.  However, based on
NSTAR's assessment to date, the adoption of SFAS 143 is not
expected to have a material effect on its results of operations,
cash flows, or financial position.

As of January 1, 2001, NSTAR adopted SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities" (SFAS 133), as
amended by SFAS Nos. 137 and 138, and collectively referred to as
SFAS 133.  SFAS 133 established accounting and reporting
standards requiring that every derivative instrument (including
certain derivative instruments embedded in contracts possibly
including fixed-price fuel supply and power contracts) be
recorded on the Consolidated Balance Sheets as either an asset or
liability measured at its fair value.

The management of NSTAR has assessed the impact of the adoption
of SFAS 133.  As part of this assessment, NSTAR formed an
implementation team in 2000 consisting of key individuals from
various operational and financial areas of the organization.  The
primary role of this team was to inventory and determine the
impact of potential contractual arrangements for SFAS 133
application.  The implementation team performed extensive reviews
of critical operating areas of NSTAR and documented its
procedures in applying the requirements of SFAS 133 to NSTAR's
contractual arrangements in effect on January 1, 2001.  NSTAR
continues its assessment on any impact that potentially may
result from FASB revisions and clarifications, including, but not
limited to, FASB Derivative Implementation Group Issue C15, to
SFAS 133.  Based on NSTAR's assessment, the adoption of SFAS 133
has not had a material effect on its results of operations, cash
flows, or financial position.

Note B. Earnings Per Common Share

Basic earnings per common share (EPS) is calculated by dividing
net income, after deductions for preferred dividends, by the
weighted average common shares outstanding during the year.  SFAS
No. 128, "Earnings per Share," requires the disclosure of diluted
EPS.  Diluted EPS is similar to the computation of basic EPS
except that the weighted average common shares is increased to
include the number of potential dilutive common shares.  Diluted
EPS reflects the impact on shares outstanding of the deferred
(nonvested) shares and stock options granted under the NSTAR
Stock Incentive Plan.

<TABLE>
<CAPTION>
The following table summarizes the reconciling amounts between
basic and diluted EPS:
<S>                                                <C>          <C>       <C>
(in thousands, except per share amounts)                2001        2000      1999
Earnings (loss) available for common shareholders    $(2,426)    $175,002  $140,503
Basic EPS                                            $ (0.05)    $   3.19  $   2.77
Diluted EPS                                          $ (0.05)    $   3.18  $   2.76
Weighted average common shares outstanding for
  basic EPS                                           53,033       54,887    50,796
Effect of dilutive shares:
Weighted average dilutive potential common
   shares                                                183          158       125
Weighted average common shares
outstanding for  diluted EPS                          53,216       55,045    50,921
                                                      ======       ======    ======
</TABLE>

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 has accounted for its equity
investment in the joint venture using the equity method of
accounting.  As part of the Joint Venture Agreement, NSTAR Com
has the option to exchange portions of its joint venture interest
for common shares of RCN at specified periods.  To date, NSTAR
Com has received approximately 4.1 million shares of RCN common
shares from two prior exchanges of its joint venture interest.

On April 6, 2000, NSTAR Com issued its third and final notice to
exchange substantially all of its remaining interest in the joint
venture into common shares of RCN.  Effective with the third
notice, NSTAR Com's profit and loss sharing ratio was reduced.
During 2000, NSTAR Com recognized $5.6 million in equity losses
from the joint venture.

On October 18, 2000, NSTAR Com and RCN signed an agreement in
principle to amend the Joint Venture Agreement.  Among other
items, this proposal settled the number of shares to be received
for the third conversion of NSTAR Com's remaining equity
investment at 7.5 million shares.  After extensive discussions
and negotiations, NSTAR Com is finalizing revisions to this
agreement and management anticipates having a definitive amended
Joint Venture Agreement in 2002.

As previously disclosed, management continues to evaluate the
carrying value of its entire investment in RCN.  Consistent with
the performance of the telecommunications sector as a whole, the
market value of RCN's common shares decreased significantly
during the later part of 2000 and continued in 2001.  As a
result, in the first quarter of 2001, management determined that
this decline in market value was "other-than-temporary" in
accordance with the SFAS No. 115, "Accounting for Certain
Investments in Debt and Equity Securities."  The market value of
RCN common shares has continued to decline in the early part of
2002.  Management cannot determine whether this trend will
continue or if or when this sector or RCN's common share value
will recover.  However, should this trend continue for a period
of six months or longer, NSTAR may be required to recognize an
additional impairment charge in 2002.  Should an impairment
charge be necessary, it is reasonably possible that this could
have a material adverse effect on NSTAR's result of operations.

Also, during the first quarter of 2001, the status of the
amendment to the Joint Venture Agreement with RCN regarding the
7.5 million shares led management to determine that its
investment in the joint venture was also impaired based on future
market expectations for RCN common shares related to this
investment.

As a result, NSTAR Com, recognized an impairment of its entire
investment in RCN in the first quarter of 2001.  This write-down
resulted in a non-cash, after-tax charge of $173.9 million that
is reported on the accompanying Consolidated Statements of Income
as "Write-down of RCN investment, net."

The RCN shares received, as well as the remaining interest in the
joint venture related to the pending 7.5 million shares, are
included in Other investments on the accompanying Consolidated
Balance Sheets at their estimated fair value of approximately
$40.1 million at December 31, 2001.  The fair value of the shares
currently held may increase or decrease, at any time, as a result
of changes in the market value of RCN common shares.  As of
December 31, 2001 and 2000, the market values of these shares
were $2.93 and $6.31, respectively.  The unrealized gain or loss
associated with shares currently held will fluctuate due to the
changes in fair value of these shares during each period and is
reflected, net of associated income taxes, as a component of
Other comprehensive income (loss), net on the accompanying
Consolidated Statements of Comprehensive Income (Loss).  The
cumulative increase or decrease in fair value of these shares as
of December 31, 2001 reflects the change since the write-down of
these shares as a component of Accumulated other comprehensive
income (loss) on the accompanying Consolidated Balance Sheets.

At December 31, 2001 and 2000, NSTAR Com had $2.6 million and
$47.9 million, respectively, in accounts receivable due from the
joint venture.  Amounts due are primarily the result of
construction performed by NSTAR Com on behalf of the joint
venture.

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.  This is applicable to
NSTAR's distribution and transmission operations, in addition to
its remaining generation business that relates to Canal's  3.52%
joint ownership interest in the Seabrook Nuclear Power Station
(Seabrook).

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 through 2016 for Boston Edison and through 2026
for ComElectric and Cambridge Electric.  This schedule is subject
to adjustment by the MDTE.

b. Fuel and purchased power charge

The fuel and purchased power charge ceased in 1998. The net
remaining over-collection of fuel and purchased power costs were
returned to customers in 1999 and 2000.

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
through 2004.  The cost of providing standard offer service
includes fuel and purchased power costs.  Default service is the
electricity that is supplied by the local distribution company
when a customer is not receiving power from standard offer
service.  The market price for standard offer and default service
will fluctuate based on the average market price for power.
Amounts collected through standard offer and default service are
recovered on a fully reconciling basis.

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's distribution rates were subject to a minimum and
maximum return on average common equity from its distribution
business through December 31, 2000.

The cost of providing transmission service to all NSTAR Electric
distribution customers is recovered on a fully reconciling basis
plus an approved return.

2. Service Quality Index

On October 29, 2001, and as subsequently updated, NSTAR Electric
and NSTAR Gas each filed with the MDTE proposed service quality
plans for each company, which replaced the service quality plan
that had previously been filed as a part of the NSTAR merger rate
plan and includes guidelines that had been established by the
MDTE as a result of its generic investigation of service quality
issues.  The service quality plans established performance
benchmarks effective January 1, 2002 for certain identified
measures of service quality relating to customer service and
billing performance, customer satisfaction, and reliability and
safety performance.  The companies are required to report
annually concerning their performance as to each measure and are
subject to maximum penalties of up to two percent of transmission
and distribution revenues should performance fail to meet the
applicable benchmarks.  On October 29, 2001, NSTAR Electric and
NSTAR Gas also filed with the MDTE a report concerning their
performance on the identified service quality measures for the
two twelve-month periods ended August 31, 2000 and 2001.  This
report included a calculation of penalties in accordance with
MDTE guidelines whereby penalties were calculated totaling
approximately $3.9 million relating primarily to Boston Edison's
electric system reliability performance for the summer of 2001.
NSTAR disputes the legal applicability of penalties for these
performance periods; however, NSTAR proposed in settlement of
this matter to provide credits to Boston Edison customers
totaling $3.9 million, offset in part by other payments to Boston
Edison customers, which totaled approximately $1 million,
relating to summer 2001 electric service outages.  On March 22,
2002, following hearings on the matter, the MDTE issued an order
imposing a service quality penalty of approximately $3.25 million
to be refunded to customers as a credit to their bills in 2002.

Also on October 29, 2001, NSTAR Electric filed with the MDTE a
comprehensive report regarding electric system performance issues
encountered during the summer of 2001.  The filing included
detailed analyses of factors affecting performance, as well as,
the companies' plans to address issues identified.  The MDTE also
requested similar filings from other Massachusetts electric
distribution companies and has held public hearings and will hold
adjudicatory hearings concerning each such filing.  On January
30, 2002, the AG and the Massachusetts Division of Energy
Resources (DOER) filed comments urging the MDTE to assess the
maximum penalties allowed pursuant to the established service
quality benchmarks and to require an independent management audit
as a result of alleged service quality deficiencies.  On February
6, 2002, NSTAR Electric filed its brief arguing against the AG's
and DOER's positions.  On March 22, 2002, following a number of
public hearings throughout the NSTAR Electric service area, the
MDTE issued an order finding that NSTAR Electric had made
progress in addressing the issues which initiated the
investigation and requiring that NSTAR Electric submit further
updated reports on specific issues on a quarterly and annual
basis.  NSTAR is unable to estimate its ultimate liability for
future costs or penalties as a result of any further filings
relating to this investigation.  However, in view of NSTAR's
current assessment of its electric distribution system
performance responsibilities, existing legal requirements and
regulatory policies, management believes it would not have a
material effect on NSTAR's consolidated financial position, cash
flows or results of operations for a reporting period.

3. Generating Asset Divestiture

On October 26, 2000, the MDTE approved the filing made by
ComElectric and Cambridge Electric (together, "the Companies")
for the partial buydown of their contract with Canal for power
from Seabrook.  In November 2000, a total of $141.6 million of
funds held by an affiliate, Energy Investment Services, Inc.
(EIS), was transferred to the Companies.  EIS was established as
the vehicle to invest the net proceeds from the sale of the
Companies' generation assets.  The Companies, in turn, reduced
their respective future costs to be recovered from customers.
The FERC and the MDTE approved Canal's request to reflect the
buydown effective November 1, 2000.  Canal, along with other
joint-owners of Seabrook, has begun to actively market the sale
of Seabrook.

Note E. Income Taxes

Income taxes are accounted for in accordance with SFAS No. 109,
"Accounting for Income Taxes" (SFAS 109).  SFAS 109 requires the
recognition of deferred tax assets and liabilities for the future
tax effects of temporary differences between the carrying amounts
and the tax basis of assets and liabilities.  In accordance with
SFAS 109, net regulatory assets of $53.4 million and $55.9
million and corresponding net increases in accumulated deferred
income taxes were recorded as of December 31, 2001 and 2000,
respectively.  The regulatory assets represent the additional
future revenues to be collected from customers for deferred
income taxes.

NSTAR has determined that no current or future income tax benefit
is anticipated related to the write-down of its remaining
investment in the RCN joint venture.  As a result, NSTAR recorded
in 2001 a $64.5 million valuation allowance for the entire tax
benefit associated with this charge.  If all or a portion of this
tax benefit is ultimately realized, NSTAR will reflect a
corresponding reduction in income tax expense.
<TABLE>
<CAPTION>
Accumulated deferred income taxes consisted of the following:
<S>                                <C>          <C>
                                          December 31,
(in thousands)                          2001          2000
Deferred tax liabilities:
  Plant-related                     $351,882      $335,525
  Transition costs                   233,465       291,222
  Other                              313,480       351,046
                                     898,827       977,793

Deferred tax assets:
  Plant-related                       61,543        82,898
  Investment tax credits              23,956        25,791
  Other                              154,600       202,560
                                     240,099       311,249
Net accumulated deferred income     $658,728      $666,544
taxes                               ========      ========
</TABLE>

Previously deferred investment tax credits are amortized over the
estimated remaining lives of the property giving rise to the
credits.
<TABLE>
<CAPTION>
Components of income tax expense were as follows:
<S>                                      <C>         <C>        <C>
(in thousands)                                2001       2000        1999
Current income tax expense (benefit)       $148,230    $ 68,944   $(33,121)
Deferred income tax expense (benefit)       (32,735)     50,461    123,393
Investment tax credit amortization           (2,083)     (1,985)    (2,551)
  Income taxes charged to operations        113,412     117,420     87,721
Tax expense (benefit) on other income
  (deductions), net                          12,032      11,480    (27,580)
  Total income tax expense                 $125,444    $128,900   $ 60,141
                                           ========    ========   ========
 </TABLE>

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:
<TABLE>
<CAPTION>
<S>                                               <C>     <C>     <C>
                                                    2001    2000   1999
Statutory tax rate                                  35.0%   35.0%  35.0%
State income tax, net of federal income tax benefit  5.3     5.1    5.5
Investment tax credits                              (0.7)   (0.6) (11.3)
Other                                                0.6     2.1   (0.1)
Effective tax rate before write-down of RCN         40.2    41.6   29.1
Write-down of RCN investment (federal and state)    57.3       -      -
  Effective tax rate                                97.5%   41.6%  29.1%
                                                    ====    ====  =====
</TABLE>

Income tax expense is reflected net of $20.8 million in 1999,
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 1999.

Note F. Pension and Other Postretirement Benefits

1. Pension

NSTAR sponsors a defined benefit funded retirement plan that
covers substantially all employees. NSTAR also maintains unfunded
supplemental retirement plans for certain management employees.
<TABLE>
<CAPTION>
The changes in benefit obligation and plan assets were as
follows:
<S>                                               <C>          <C>
                                                         December 31,
(in thousands)                                         2001        2000
Change in benefit obligation:
  Benefit obligation, beginning of the year         $804,358      $800,084
  Service cost                                        14,082        14,636
  Interest cost                                       57,381        59,798
  Plan participants' contributions                        71            81
  Plan amendments                                          -       (4,387)
  Actuarial loss                                      14,579        59,815
  Settlement payments                                (17,176)      (77,256)
  Benefits paid                                      (48,993)      (48,413)
    Benefit obligation, end of the year             $824,302      $804,358
                                                    ========      ========

Change in plan assets:
  Fair value of plan assets, beginning of the year  $846,207      $955,498
  Actual loss on plan assets, net                    (52,493)      (28,041)
  Employer contribution                               63,088        44,338
  Plan participants' contributions                        71            81
  Settlement payments                                (17,176)      (77,256)
  Benefits paid                                      (48,993)      (48,413)
    Fair value of plan assets, end of the year      $790,704      $846,207
                                                    ========      ========
</TABLE>
<TABLE>
<CAPTION>
The plan's funded status was as follows:
<S>                                              <C>            <C>
                                                         December 31,
(in thousands)                                         2001         2000
Funded status                                       $(33,598)     $ 41,849
Unrecognized actuarial net loss                      249,456       104,817
Unrecognized transition obligation                     1,581         2,182
Unrecognized prior service cost                       (3,420)       (3,340)
    Net amount recognized                           $214,019      $145,508
                                                    ========      ========
</TABLE>
<TABLE>
<CAPTION>
Amount recognized in the Consolidated Balance Sheets consisted
of:
<S>                                               <C>            <C>
                                                        December 31,
(in thousands)                                        2001          2000
Prepaid retirement cost                             $218,713      $149,890
Accrued supplemental retirement liability            (10,547)      (13,306)
Intangible asset                                       5,853         7,285
Accumulated other comprehensive income                     -         1,639
  Net amount recognized                             $214,019      $145,508
                                                    ========      ========
</TABLE>
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 $13,785,000, $10,547,000 and $0, respectively, as of
December 31, 2001 and $14,067,000, $13,306,000 and $0,
respectively, as of December 31, 2000.
<TABLE>
<CAPTION>
Weighted average assumptions were as follows:
<S>                                       <C>       <C>     <C>
                                           2001      2000    1999
Discount rate at the end of the year       7.25%      7.5%    8.0%
Expected return on plan assets for the
  year (net of investment expenses)         9.4%      9.3%    9.0%
Rate of compensation increase at the end
  of the year                               4.0%      4.0%    4.0%
</TABLE>
<TABLE>
<CAPTION>
Components of net periodic benefit (income)/cost were as follows:
<S>                                 <C>          <C>       <C>
                                          Years ended December 31,
(in thousands)                          2001       2000       1999
Service cost                         $ 14,082     $ 14,636   $ 14,741
Interest cost                          57,381       59,798     42,426
Expected return on plan assets        (78,397)     (85,884)   (53,059)
Amortization  of  prior service cost       80          448      1,610
Amortization of transition obligation     601          601        664
Recognized actuarial loss                 830            -      3,594
Net periodic benefit(income)/cost    $ (5,423)    $(10,401)  $  9,976
                                     ========     ========   ========

</TABLE>
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 are a component of Regulatory assets
on the accompanying Consolidated Balance Sheets.  The previous
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.

2. Savings Plan

NSTAR also provides a defined contribution 401(k) plan for
substantially all employees. Matching contributions (which are
equal to 50% of the employees' deferral up to 8% of compensation)
included in the accompanying Consolidated Statements of Income
amounted to $9 million in 2001, $7 million in 2000 and $9 million
in 1999.  The plan was amended, effective April 1, 2001, to allow
participants the ability to reallocate their investments in NSTAR
common shares to other investment options.  Effective January 1,
2002, consistent with the Economic Growth and tax Relief
Reconciliation Act of 2001, the plan was further amended to allow
for increased maximum annual pre-tax contributions and additional
"catch-up" pre-tax contributions for participants age 50 or
older, acceptance of other types of "roll-over" pre-tax funds
from other plans and the option of reinvesting dividends paid on
the NSTAR Common Share Fund or receiving such dividends in cash.

3. 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.
<TABLE>
<CAPTION>
The changes in benefit obligation and plan assets were as
follows:
<S>                                               <C>          <C>
                                                         December 31,
(in thousands)                                         2001        2000
Change in benefit obligation:
  Benefit obligation, beginning of the year         $ 428,341   $ 370,914
  Service cost                                          4,332       3,563
  Interest cost                                        31,662      29,574
  Plan participants' contributions                      1,811         926
  Plan amendments                                           -       2,807
  Actuarial loss                                       30,716      44,939
  Benefits paid                                       (26,959)    (24,382)
    Benefit obligation, end of the year             $ 469,903   $ 428,341
                                                    =========   =========

Change in plan assets:
  Fair value of plan assets, beginning of the year  $ 224,651   $ 201,053
  Actual loss on plan assets                          (13,376)    (16,411)
  Employer contribution                                39,721      63,465
  Plan participants' contributions                      1,811         926
  Benefits paid                                       (26,959)    (24,382)
    Fair value of plan assets, end of the year      $ 225,848   $ 224,651
                                                    =========   =========

</TABLE>
<TABLE>
<CAPTION>
The plans' funded status and amount recognized in the
accompanying Consolidated Balance Sheets were as follows:
<S>                                         <C>          <C>
                                                 December 31,
(in thousands)                                  2001         2000

Funded status                                 $(244,055)   $(203,690)
Unrecognized actuarial net loss                 134,006       70,836
Unrecognized transition obligation               61,784       67,400
Unrecognized prior service cost                 (16,233)     (17,644)
    Net amount recognized                     $ (64,498)   $ (83,098)
                                               =========   =========
</TABLE>
<TABLE>
<CAPTION>
Weighted average assumptions were as follows:
<S>                                           <C>    <C>     <C>
                                                2001    2000    1999
Discount rate at the end of the year            7.25%    7.5%    8.0%
Expected  return on plan assets  for the year    9.0%    9.0%    9.0%

</TABLE>
For measurement purposes a 9% weighted annual rate of increase in
per capita cost of covered medical claims was assumed for 2002.
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.
<TABLE>
<CAPTION>
A 1% change in the assumed health care cost trend rate would have
the following effects:
<S>                                        <C>         <C>
                                              One-Percentage-Point
(in thousands)                               Increase    Decrease
Effect on total service and interest costs
components for 2001                          $ 3,080     $ (2,503)
Effect on December 31, 2001 postretirement
benefit obligation                           $37,281     $(30,499)

</TABLE>

<TABLE>
<CAPTION>
Components of net periodic benefit cost were as follows:
<S>                                  <C>        <C>        <C>
                                           Years ended December 31,
(in thousands)                           2001        2000        1999

Service cost                          $  4,332     $  3,563    $  4,505
Interest cost                           31,662       29,574      21,896
Expected return on plan assets         (21,430)     (19,010)    (12,329)
Amortization  of prior service cost     (1,411)      (1,703)       (683)
Amortization of transition obligation    5,616        5,616       6,162
Recognized actuarial loss                2,352            -         957
  Net periodic benefit cost           $ 21,121     $ 18,040    $ 20,508
                                      ========    =========     =======
</TABLE>

Note G. Stock-Based Compensation

The NSTAR 1997 Share Incentive Plan (the Plan) permits a variety
of stock and stock-based awards, including stock options and
deferred (non-vested) stock to be granted to key employees.  The
Plan limits the terms of awards to ten years. Subject to
adjustment for stock-splits and similar events, the aggregate
number of common shares that may be awarded under the Plan is two
million, including shares issued in lieu of or upon reinvestment
of dividends arising from awards.  The Plan was amended in
January 2002, subject to shareholder approval at the 2002 Annual
Meeting of Shareholders, to increase the number of shares
available for issuance to four million.  During 2001, 97,850
deferred shares and 240,500 ten-year non-qualified stock options
were granted.  During 2000, 69,750 deferred shares and 316,700
ten-year non-qualified stock options were granted.  During 1999,
58,500 deferred shares and 248,000 ten-year non-qualified stock
options were granted under the Plan.  The weighted average grant
date fair value of the deferred stock issued during 2001, 2000
and 1999 was $39.70, $44.375 and $41.73, 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:
<TABLE>
<CAPTION>
<S>                                     <C>          <C>       <C>
(in thousands, except per share amounts)     2001        2000      1999
Net income
  Actual                                 $   3,201     $180,962  $146,463
  Pro forma                              $   2,470     $180,237  $145,955
Basic earnings (loss) per common share
  Actual                                 $   (0.05)    $   3.19  $   2.77
  Pro forma                              $   (0.06)    $   3.18  $   2.76
Diluted earnings (loss) per common share
  Actual                                 $   (0.05)    $   3.18  $   2.76
  Pro forma                              $   (0.06)    $   3.17  $   2.75
</TABLE>
<TABLE>
<CAPTION>
Stock option activity of the Plan was as follows:
<S>                                 <C>        <C>         <C>
                                       2001         2000      1999
Options outstanding at January 1      918,135     814,267   666,600
  Options granted                     240,500     316,700   248,000
  Options exercised                   (47,567)   (125,432)   (4,400)
  Options forfeited                  (143,466)    (87,400)  (95,933)
Options outstanding at December 31    967,602     918,135   814,267
                                     ========    ========   =======
</TABLE>

<TABLE>
<CAPTION>
Summarized information regarding stock options outstanding at
December 31, 2001:
<S>            <C>            <C>        <C>      <C>       <C>
                               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  Prices
$25.75-$26.00     162,400       5.45      $25.90    162,400     $25.90
$39.75-$41.375    353,735       6.26      $40.36    302,805     $40.14
  $44.375         245,633       8.40      $44.375    81,059     $44.375
  $39.70          205,834       9.40      $39.70         -         -
</TABLE>

There were 546,264, 404,976 and 298,333 stock options exercisable
on December 31, 2001, 2000 and 1999, respectively.

The stock options granted during 2001, 2000 and 1999 have a
weighted average grant date fair value of $5.10, $7.00 and $4.86,
respectively.  The fair value was estimated using the Black-
Scholes option pricing model with the following weighted average
assumptions:
<TABLE>
<CAPTION>
<S>                              <C>        <C>        <C>
                                  2001        2000       1999
Expected life (years)             4.0         4.0         4.0
Risk-free interest rate          4.82%       6.48%       5.31%
Volatility                        21%          20%         17%
Dividends                        5.34%       4.64%       4.86%
</TABLE>
Compensation cost recognized in the accompanying Consolidated
Statements of Income for stock-based compensation awards in 2001,
2000 and 1999 was $2,069,000, $1,717,000 and $1,044,000,
respectively.

Note H. Capital Stock

1. Common Shares
<TABLE>
<CAPTION>
<S>                                        <C>           <C>
                                                    December 31,
(in thousands, except share amounts)              2001         2000
Common equity:
Common shares, par value $1 per share,
  100,000,000 shares authorized;
  53,032,546 shares issued and outstanding   $   53,033    $   53,033
Premium on common shares                        873,664       876,749
Retained earnings                               334,138       446,587
  Total common equity                        $1,260,835    $1,376,369
                                             ==========    ==========
</TABLE>
<TABLE>
<CAPTION>
Common share issuances and repurchases in 1999 through 2001 were
as follows:
<S>                               <C>         <C>         <C>
                                   Number of    Total       Premium on
(in thousands)                       Shares    Par Value   Common Shares
Balance at December 31, 1998         47,184     $ 47,184     $  644,205
  Common share repurchase program    (4,839)      (4,839)      (179,593)
  Share Incentive Plan                    -            -         (3,189)
  Shares issued to COM/Energy
    shareholders                     20,251       20,251        809,524
  BEC Energy shares repurchased
    under merger agreement           (4,536)      (4,536)      (195,464)
Balance at December 31, 1999         58,060       58,060      1,075,483
  Common share repurchase program    (5,027)      (5,027)      (198,113)
  Share Incentive Plan                    -            -           (621)
Balance at December 31, 2000         53,033       53,033        876,749
Share Incentive Plan and other            -            -         (3,085)
Balance at December 31, 2001         53,033     $ 53,033     $  873,664
                                    =======      =======      =========
</TABLE>

Dividends declared per common share were $2.075, $2.015 and
$1.955 in 2001, 2000 and 1999, respectively.

2. Cumulative Preferred Stock of Subsidiary

(in thousands, except per share amounts)
Par value $100 per share, 2,660,000 shares authorized and 430,000
shares issued and outstanding:
<TABLE>
<CAPTION>
Non-mandatory redeemable series:
<S>          <C>         <C>              <C>          <C>
               Current     Redemption                    December 31,
  Series        Shares    Price/Share         2001              2000
             Outstanding
   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

</TABLE>
<TABLE>
<CAPTION>
Mandatory redeemable series:
<S>        <C>          <C>              <C>          <C>
             Shares      Redemption
 Series   Outstanding    Price/Share
  8.00%      500,000       $100.00               -        50,000
Less redemption and issuance costs               -           481
  Total mandatory redeemable series              -        49,519
                                            43,000        92,519
Less amount due within one year                  -        49,519
  Total cumulative preferred
   stock of subsidiary                     $43,000       $43,000
                                           =======       =======

The 8% Series was redeemed in total on December 3, 2001, plus
accrued dividends from November 1, 2001 to December 1, 2001.
</TABLE>
Note I. Indebtedness

1.  Long-Term Debt
<TABLE>
<CAPTION>
NSTAR's long-term debt consisted of the following:
<S>                                      <C>          <C>
                                                December 31,
(in thousands)                                2001          2000
Mortgage Bonds, collateralized by
property of operating subsidiaries:
  8.99%,  due December 2001               $       -    $    3,500
  6.54%,  due September 2007                  8,571        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                       2,100         2,200
  9.30%,  due January 2002                   30,000        29,989
  7.43%,  due March 2003                     15,000        15,000
  9.50%,  due December 2004                   3,000         4,000
  7.62%,  due November 2006                  20,000        20,000
  8.70%,  due March 2007                      5,000         5,000
  9.55%,  due December 2007                   8,571        10,000
  7.70%,  due March 2008                     10,000        10,000
  8.0%,   due February 2010                 498,226       498,008
  9.37%,  due January 2012                   11,579        12,632
  7.98%,  due March 2013                     25,000        25,000
  9.53%,  due December 2014                  10,000        10,000
  9.60%,  due December 2019                  10,000        10,000
  6.924%, due June 2021                     106,058       105,994
  8.47%,  due March 2023                     15,000        15,000
Debentures:
  6.80%,  due March 2003                    150,000       150,000
  7.80%,  due May 2010                      125,000       125,000
  9.375%, due August 2021                         -        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
  through 2015                               21,470        23,014
Massachusetts Industrial Finance Agency
(MIFA) bonds:
  5.75%,  due February 2014                  15,000        15,000
Transition Property Securitization
Certificates:
  5.99%,  due March 2001                          -         4,073
  6.45%,  due through September 2005        108,986       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
                                          1,970,451     2,070,180
Amounts due within one year                 (78,648)      (45,619)
    Total long-term debt                 $1,891,803    $2,024,561
                                          =========     =========
</TABLE>

The 8.25% series debentures due 2022 are first redeemable in
September 2002 at 103.78% and the 7.80% series debentures due
2023 are first redeemable in March 2003 at 103.73%.  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 2001,
2000 and 1999.  The weighted average interest rate of the bonds
was 7.4%.

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 has approval from the MDTE to issue from time to
time up to $500 million of long-term debt securities through
2002.  In connection with this, on February 20, 2001, Boston
Edison filed a registration statement on Form S-3 with the SEC,
using a shelf registration process, to issue up to $500 million
in debt securities.  The SEC declared the registration statement
effective on February 28, 2001.  When issued, Boston Edison will
use the proceeds to pay at maturity long-term debt and equity
securities, refinance short-term debt and for other corporate
purposes.  No issuance of debt securities were made during 2001
under this authorization.

The aggregate principal amounts of NSTAR long-term debt
(including securitization certificates and sinking fund
requirements) due in the five years subsequent to 2001 are
approximately $108 million in 2002, $241 million in 2003, $79
million in 2004, $78 million in 2005 and $98 million in 2006.

NSTAR and Boston Edison have no covenant requirements under their
long-term debt arrangements.  COM/Electric, Cambridge Electric
and NSTAR Gas have covenant requirements under their long-term
debt arrangements and were in compliance at December 31, 2001 and
2000.

2. Short-Term Debt

NSTAR has a $450 million revolving credit agreement with a group
of banks effective through November 2002. There were no amounts
outstanding as of December 31, 2001 and 2000 under this revolving
credit agreement.  This arrangement serves as back-up to NSTAR's
$450 million commercial paper program.  NSTAR anticipates
renewing its revolving credit agreement under similar terms.  At
December 31, 2001 and 2000, NSTAR had $315.5 million and $252
million outstanding, respectively, under its 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 approval from the FERC to issue up to $350
million of short-term debt.  Boston Edison has a $300 million
revolving credit agreement with a group of banks effective
through December 2002.  At December 31, 2001 and 2000, there were
no amounts outstanding under this revolving credit agreement.
This arrangement serves as back-up to Boston Edison's $300
million commercial paper program that, at December 31, 2001 and
2000, had outstanding $191.5 million and $96.5 million,
respectively.  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.  Separately, Boston Edison, effective July 20,
2001, has an additional $50 million line of credit with no
outstanding amounts at December 31, 2001.

In addition, ComElectric, Cambridge Electric and NSTAR Gas,
collectively, have $190 million available under several lines of
credit that will expire at varying intervals in 2002.  These
lines are normally renewed upon expiration and commitment fees
are required.  Approximately $118 million and $120 million were
outstanding under these lines of credit as of December 31, 2001
and 2000, respectively.  ComElectric, Cambridge Electric and
Canal have approval from FERC to issue short-term debt with
amounts ranging from $60 million to $100 million.

Interest rates on the outstanding borrowings generally are money
market rates and averaged 4.13% and 6.65% in 2001 and 2000,
respectively.  In aggregate, notes payable to banks discussed
above totaled $624.8 million and $468.3 million at December 31,
2001 and 2000, 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 $11.7 million and $21.9 million for 2001
and 2000, respectively, approximate fair value due to the short-
term nature of these securities.

2. Mandatory Redeemable Cumulative Preferred Stock and
Indebtedness (Excluding Notes Payable).
<TABLE>
<CAPTION>
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, 2001 and 2000 were as follows:
<S>                           <C>         <C>         <C>             <C>
                                         2001                      2000
                                 Carrying       Fair      Carrying         Fair
(in thousands)                    Amount        Value       Amount         Value
Mandatory redeemable
cumulative preferred stock      $    -      $        -    $   49,519   $   50,890
Long-term indebtedness
(including current maturities)  $1,970,451  $2,076,190    $2,070,180   $2,090,290
</TABLE>

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  including
telecommunications, district heating and cooling operations, and
a liquefied natural gas service.  Financial data for the
operating segments were as follows:
<TABLE>
<CAPTION>
<S>                                 <C>        <C>         <C>

(in thousands)                        2001          2000       1999(c)
Operating revenues
  Electric utility operations     $2,668,509     $2,204,332  $1,710,576
  Gas utility operations             397,990        378,626     108,117
  Unregulated operations             125,337        109,804      32,734
    Consolidated total            $3,191,836     $2,692,762  $1,851,427
                                  ==========     ==========  ==========
Depreciation and amortization
  Electric utility operations     $  197,233     $  202,209  $  190,560
  Gas utility operations              16,588         15,573       5,566
  Unregulated operations              17,128         20,826      14,180
    Consolidated total            $  230,949     $  238,608  $  210,306
                                  ===========    ==========  ==========
Operating income tax expense(benefit)
  Electric utility operations     $  106,349     $  112,310  $   98,125
  Gas utility operations              14,031         15,514       4,208
  Unregulated operations              (6,968)       (10,404)    (14,612)
    Consolidated total            $  113,412     $  117,420  $   87,721
                                   =========     ==========  ==========
Equity income (loss) in investments
 accounted for by the equity method (a)
  Electric utility operations     $    2,258     $   4,241   $      999
  Unregulated operations                   -        (5,467)     (10,505)
    Consolidated total            $    2,258     $  (1,226)  $   (9,506)
                                  ==========     =========   ==========
Interest charges
  Electric utility operations     $  133,019     $  156,205  $  106,878
  Gas utility operations              14,505         13,257       3,742
  Unregulated operations              31,064         35,931      14,693
    Consolidated total            $  178,588     $  205,393  $  125,313
                                  ==========     ==========  ==========
Segment net income (loss) (b)
  Electric utility operations     $  169,642     $  176,112  $  165,626
  Gas utility operations              21,225         22,950       5,379
  Unregulated operations            (187,666)      (18,100)     (24,542
    Consolidated total            $    3,201     $  180,962  $  146,463
                                  ==========     ==========  ==========
Equity Investments
  Electric utility operations     $   22,560     $   25,791  $   32,995
  Unregulated operations                   -              -     140,286
    Consolidated total            $   22,560     $   25,791  $  173,281
                                  ==========     ==========  ==========
Expenditures for property
  Electric utility operations     $  180,300     $  141,400  $  134,906
  Gas utility operations              26,900         19,500       7,669
  Unregulated operations              21,504         21,809      16,720
    Consolidated total            $  228,704     $  182,709  $  159,295
                                  ==========     ==========  ==========
Segment assets
  Electric utility operations     $4,509,982     $4,557,948  $4,409,630
  Gas utility operations             517,659        541,406     459,887
  Unregulated operations             300,550        448,361     596,626
    Consolidated total            $5,328,191     $5,547,715  $5,466,143
                                  ==========     ==========  ==========

</TABLE>
(a) The equity income (loss) from equity investments is included
in other income (expense), net on the accompanying Consolidated
Statements of Income.

(b) The net income (loss) for 2001 includes the impact of a non-
cash, after-tax charge of $173.9 million, or $3.28 per share,
related to the write-down of NSTAR's investment in RCN
Corporation and is reflected in the results of unregulated
operations.

(c) Financial data for 1999 includes eight months of BEC Energy
and four months of NSTAR.

Note L. Commitments and Contingencies

1. Contractual Commitments
<TABLE>
<CAPTION>
NSTAR also has leases for facilities and equipment.  The
estimated minimum rental commitments under non-cancellable
capital and operating leases for the years after 2001 are as
follows:
<S>                                       <C>
(in thousands)
2002                                         $   23,489
2003                                             19,389
2004                                             18,315
2005                                             16,594
2006                                             15,205
Years thereafter                                 57,675
  Total                                      $  150,667
                                             ==========
</TABLE>
The total expense for both lease rentals and transmission
agreements was $57.1 million in 2001, $45.3 million in 2000 and
$38.7 million in 1999, net of capitalized expenses of $2.3
million in 2001, $1.7 million in 2000 and $1.5 million in 1999.

Total rent expense for all operating leases, except those with
terms of a month or less, amounted to $8.3 million in 2001, $8.7
million in 2000 and $10.8 million in 1999.

NSTAR Electric has entered into a series of short-term purchased
power agreements to meet its entire default service supply
obligations and its remaining unmet standard offer supply
obligations through December 31, 2002.  NSTAR Electric is
completely recovering all of the payments it is making to
suppliers and has financial and performance assurances and
financial guarantees in place with those suppliers to protect
NSTAR Electric from risk in the unlikely event any of its
suppliers encounter financial difficulties or fail to maintain an
investment grade credit rating.  In connection with certain of
these agreements, should, in the unlikely event, an individual
NSTAR Electric distribution company receive a credit rating below
investment grade, that company potentially could be required to
obtain certain financial commitments, including but not limited
to, letters of credit.

2. Electric Equity Investments and Joint Ownership Interest

NSTAR Electric has an equity investment of approximately 14.5% in
two companies that own and operate transmission facilities to
import electricity from the Hydro-Quebec system in Canada.  As an
equity participant, NSTAR Electric is required to guarantee, in
addition to each companies' own share, the obligations of those
participants who do not meet certain credit criteria.  At
December 31, 2001, NSTAR Electric's portion of these guarantees
amounted to $14.4 million.  New England Hydro-Transmission
Electric Company, Inc. (NEH) and New England Hydro-Transmission
Corporation (NHH) have agreed to use their best efforts to limit
their equity investment to 40% of their total capital during the
time NEH and NHH have outstanding debt in their capital
structure.  In order to meet its best efforts obligation pursuant
to the Equity Funding Agreement dated June 1, 1985, as amended,
for NEH and NHH, in September 2001, NEH repurchased a total of
250,000 of its outstanding shares from all equity holders and NHH
repurchased a total of 1,100 outstanding shares from all equity
holders.  Through December 31, 2001, NSTAR Electric's reduction
of its equity ownership resulting from NEH buy-back of 36,168
shares and NHH buy-back of 159 shares was approximately $814,000.

Canal owns a 3.52% joint ownership interest in the Seabrook
Nuclear Power Station, and sells its energy and capacity
entitlement to ComElectric and Cambridge Electric.  The estimate
of NSTAR's share of the costs of decommissioning Seabrook was
approximately $5.2 million as of December 31, 2001.  These
estimates were recorded on the accompanying Consolidated Balance
Sheets as a Power contract liability and an offsetting asset in
Other investments.  Canal, along with other joint-owners of
Seabrook, has begun to actively market the sale of Seabrook.

NSTAR Electric also has a 2.5% equity investment in the 540 MW
Vermont Yankee nuclear power plant.  NSTAR Electric is entitled
to electricity produced from the facility based on its ownership
interest, and is billed for its entitlement pursuant to a
contractual agreement that is approved by the FERC.  The
estimated cost to decommission this plant is $471.1 million in
current dollars. NSTAR Electric's share of this liability is
approximately $11.8 million, less its share of the market value
of the assets held in a decommissioning trust of approximately
$7.4 million, is approximately $4.4 million at December 31, 2001.
Vermont Yankee has received the approval of the FERC to include
charges for the estimated costs of decommissioning its unit in
the cost of energy that it sells.  Periodically, Vermont Yankee
re-estimates the cost of decommissioning and applies to the FERC
for increased rates in response to increased decommissioning
costs.  The Vermont Yankee unit was under agreement to be sold to
Amergen Energy Company (Amergen), but this transaction was
disapproved on February 14, 2001 by Vermont's regulatory
authority. Subsequently, in 2001, FERC approved an agreement
between Vermont Yankee and intervening parties that included,
among other things, a settlement on the regulatory treatment of
costs incurred in conjunction with initiatives, including
Amergen, to sell the plant and related assets and liabilities.

On August 15, 2001, Vermont Yankee executed a Purchase and Sale
Agreement with the intent to sell the plant and related assets
and liabilities, including the liability to decommission the
plant, to Entergy Nuclear Vermont Yankee, LLC.  The sale of the
plant, as contemplated, would likely result in the transfer of
responsibility for decommissioning the plant to the new owner and
make future decommissioning collections unnecessary.

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.  As of December 31, 2001,
this program was completed and 145,730 shares, were redeemed.
NSTAR Electric's reduction of its equity ownership resulting from
the buy-back of 20,402 shares was approximately $2 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 its remaining investment
in CYAPC and estimated costs of decommissioning is approximately
$33 million as of December 31, 2001.  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 was
developed.  In October 1998, both CYAPC and Northeast Utilities,
a 49% equity investor in CYAPC, filed briefs on exceptions to the
ALJ decision.  During April 2000, CYAPC signed settlement
agreements with the major intervening parties in the 1996 FERC
rate case.  CYAPC received final FERC approval related to the
settlement agreements and revised rates went into effect
September 1, 2000.  CYAPC received FERC approval on September 11,
2000, regarding the decommissioning collections, a return on
equity of 6% and full recovery of assets.

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.  During 2001, Maine Yankee initiated a
stock buy-back program to redeem 75,200 of shares outstanding.
Through December 31, 2001, NSTAR Electric's reduction of its
equity ownership resulting from the buy-back of 3,008 shares was
approximately $400,000.

NSTAR Electric's share of Maine Yankee's remaining
decommissioning costs is approximately $19.6 million as of
December 31, 2001.  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 equity investments 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 Nuclear Electric
Insurance Limited (NEIL).  NEIL provides $2.75 billion of
property, boiler, machinery and decontamination insurance
coverage, including accidental premature decommissioning
insurance.  All companies insured with NEIL are subject to
retroactive assessments.  Three of the four units in which NSTAR
has equity investments 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 investments 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

NSTAR's subsidiaries are involved in 26 state-regulated
properties ("Massachusetts Contingency Plan, or "MCP" sites")
where oil or other hazardous materials were previously spilled or
released.  The NSTAR subsidiaries are required to clean up or
otherwise remediate these properties in accordance with specific
state regulations.  There are uncertainties associated with the
remediation costs due to the final selection of the specific
cleanup technology and the particular characteristics of the
different sites.  In addition to the MCP sites, NSTAR
subsidiaries also face possible liability as a potentially
responsible party (PRP) in the cleanup of eight multi-party
hazardous waste sites in Massachusetts and other states where one
or more NSTAR subsidiaries are 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 $5.8 million
and $7 million are included as liabilities in the accompanying
Consolidated Balance Sheets at December 31, 2001 and 2000,
respectively, related to the non-recoverable portion of these
cleanup liabilities.  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 possible that additional provisions for cleanup costs that may
result from a change in estimates could have an 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 over a 7-year period without carrying
costs.  As of December 31, 2001, NSTAR Gas has recorded a
liability of $6.7 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 and as either additional sites are
identified or NSTAR's responsibilities for such sites are
resolved.  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. Legal Proceedings

a. Industry and corporate restructuring legal proceedings

The 1998 MDTE order approving the Boston Edison electric
restructuring settlement agreement was appealed by certain
parties to the Massachusetts Supreme Judicial Court. One appeal
remains pending.  However, there has to date been no briefing,
hearing or other action taken with respect to this proceeding.
Management is currently unable to determine the outcome of this
proceeding. However, if an unfavorable outcome were to occur,
there could be a material adverse impact on business operations,
the consolidated financial position, cash flows and the results
of operations for a reporting period.

b. Regulatory proceedings

In a Boston Edison reconciliation filing for 1999 with the MDTE
reflecting final costs and revenues through 1998, the AG
contested cost allocations related to Boston Edison's wholesale
customers.  On June 1, 2001, the MDTE approved Boston Edison's
revenue-credit approach for wholesale sales to be consistent with
Boston Edison's restructuring settlement.  The reconciliation of
wholesale revenues and costs, along with other reconciliation
issues, were addressed in Boston Edison's 2000 filing covering
the reconciliation of costs through December 31, 2000.  On
November 16, 2001, the MDTE approved a Settlement Agreement
between Boston Edison and the AG resolving all outstanding issues
in this filing.  This settlement agreement did not have a
material effect on NSTAR's consolidated financial position or
results of operations.

In October 1997, the MDTE opened a proceeding to investigate
Boston Edison's compliance with a 1993 order that permitted the
formation of Boston Energy Technology Group, Inc. (BETG) and
authorized Boston Edison to invest up to $45 million in non-
utility activities.  On December 28, 2001, the MDTE issued its
order ruling that Boston Edison exceeded the $45 million
investment cap set by the MDTE in 1993 by $3.9 million.  BETG was
ordered to return this amount to Boston Edison within 30 days.
This reimbursement occurred in January 2002.  Boston Edison was
also ordered to pay approximately $1.9 million representing
carrying charges on the over-investment amount since December 31,
1997 to current customers in the form of a credit to Boston
Edison's transition costs.  Accordingly, this credit has been
recorded and is included in the accompanying Consolidated Balance
Sheets as a reduction of Regulatory assets.  This change had no
material adverse effect on NSTAR's consolidated financial
position or results of operations.

c. Other legal matters

In the normal course of its business, NSTAR and its subsidiaries
are also involved in certain other legal matters.  Management is
unable to fully determine a range of reasonably possible legal
costs in excess of amounts accrued.  Based on the information
currently available, it does not believe that it is probable that
any such additional costs will have a material impact on its
consolidated financial position.  However, it is reasonably
possible that additional legal costs that may result from a
change in estimates could have a material impact on the results
of a reporting period in the near term.

Note M. Long-Term Contracts for the Purchase of Energy

1. NSTAR Electric Agreements

NSTAR Electric has existing long-term power purchase agreements
that are expected to supply approximately 90%-95% of its standard
offer service obligations.  NSTAR Electric has entered into a
series of short-term power purchase agreements to meet its entire
default service supply obligations and its remaining unmet
standard offer supply obligations through December 31, 2002.
NSTAR Electric expects to continue to make periodic market
solicitations for default service and standard offer power supply
consistent with provisions of the Restructuring Act and MDTE
orders.

Capacity costs of long-term contracts reflect NSTAR Electric's
proportionate share of capital and fixed operating costs of
certain generating units.  In 2001, these costs were attributed
to 991.6 MW of capacity purchased.  Energy costs are paid to
generators based on a price per kWh actually received into NSTAR
Electric's distribution system and are included in the total
cost.  Total capacity purchased in 2001 was 1,973 MW.
<TABLE>
<CAPTION>
Information related to long-term power contracts as of December
31, 2001 was as follows:
<S>            <C>         <C>       <C>       <C>        <C>     <C>
                                             Proportionate share (in thousands)
                                                                     Capacity Charge
                 Range of         Units of         2001      2001         Obligation
Fuel Type of    Expiration        Capacity       Capacity   Total   Through Contract
Generating Unit   Dates           Purchased        Cost      Cost    Expiration Date
                               %Range  Total MW
Natural Gas     2008-2017   11.1-100    720.6    $144,390  $371,683      $1,725,410
Nuclear         2004-2026    2.3-89     799.9      14,502   180,513         481,308
Refuse            2015         100       76.9       8,226    55,058               -
Hydro           2014-2023      100       25.6           -     7,649               -
Oil             2002-2019    50-100     350.0      20,835    63,501          66,739
  Total                               1,973.0    $187,953  $678,404      $2,273,457
                                      =======    ========  ========      ==========
</TABLE>

NSTAR Electric entered into six-month agreements effective
January 1, 2001 through June 30, 2001 and July 1, 2001 through
December 31, 2001 with suppliers to provide full default service
energy and ancillary service requirements at contract rates
substantially similar to MDTE-approved tariff rates.  NSTAR
Electric's existing portfolio of power purchase contracts
supplied the majority of its standard offer (including wholesale)
energy requirements in 2001, supplemented with long-term and
daily purchases/sales in the bilateral and spot markets.  In
addition, NSTAR Electric managed its Independent System Operator-
New England Power capability responsibilities, congestion and
uplift costs associated with default service and standard offer
load throughout 2001.

NSTAR Electric's total capacity and/or energy costs associated
with these contracts in 2001, 2000 and 1999 were approximately
$678 million, $720 million and $601 million, respectively.
NSTAR Electric's capacity charge obligation under these contracts
for the years after 2001 are as follows:
<TABLE>
<CAPTION>
<S>                                <C>
                                        Capacity
                                          Charge
(in thousands)                        Obligation
2002                                  $  176,786
2003                                     166,258
2004                                     167,626
2005                                     171,234
2006                                     173,065
Years thereafter                       1,418,488
                                      $2,273,457
                                      ==========
</TABLE>

2. NSTAR Gas Contracts

NSTAR Gas has various contractual agreements covering the
transportation of natural gas, underground and liquefied natural
gas 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.  NSTAR Gas' firm contract demand
charges associated with these contracts in 2001, 2000 and 1999
were approximately $51.8 million, $54.3 million and $55.1
million.  NSTAR Gas' firm contract demand charges at current
rates under these contracts for the years after 2001 are as
follows:
<TABLE>
<CAPTION>
<S>                               <C>
                                   Firm Contract
(in thousands)                            Demand
                                         Charges
2002                                   $  51,831
2003                                      49,431
2004                                      39,575
2005                                      39,284
2006                                      37,913
Years thereafter                         200,080
                                       $ 418,114
                                       =========
</TABLE>
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 76, present
fairly, in all material respects, the financial position of NSTAR
and its subsidiaries at December 31, 2001 and 2000, and the
results of their operations and their cash flows for each of the
three years in the period ended December 31, 2001 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 76, presents fairly, in all material respects,
the information set forth therein when read in conjunction with
the related consolidated financial statements.  These financial
statements and the financial statement schedule are the
responsibility of NSTAR's management; our responsibility is to
express an opinion on these financial statements and the
financial statement schedule based on our audits. We conducted
our audits of these statements in accordance with auditing
standards generally accepted in the United States of America,
which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement.  An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating
the overall financial statement presentation.  We believe that
our audits provide a reasonable basis for our opinion.




PricewaterhouseCoopers LLP

/s/ PRICEWATERHOUSECOOPERS LLP

Boston, Massachusetts
January 31, 2002, except as to Note D(2), which is as of March
22, 2002




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 2002 Proxy Statement dated March 22, 2002.
Pages 3-5


(b) Identification of Officers

Information required by this item is included in Item 4A.


Item 11.   Executive Compensation

Information required by this item is incorporated herein by
reference to the 2002 Proxy Statement dated March 22, 2002.
Pages 9-16


Item 12.   Security Ownership of Certain Beneficial Owners and
Management

Information required by this item is incorporated herein by
reference to the 2002 Proxy Statement dated March 22, 2002.
Pages 1, 6 and 7


Item 13.   Certain Relationships and Related Transactions

Information required by this item is incorporated herein by
reference to the 2002 Proxy Statement dated March 22, 2002.  Page
4

                             Part IV

Item 14.   Exhibits, Financial Statement Schedules and Reports on
Form 8-K
<TABLE>
<CAPTION>
(a) The following documents are filed as part of this Form 10-K:
<S>                                                    <C>

1. Financial Statements:

                                                           Page
Consolidated Statements of Income for the years ended
December 31, 2001, 2000 and 1999                            42

Consolidated Statements of Comprehensive Income (Loss)
for the years ended December 31, 2001, 2000 and 1999        43

Consolidated Statements of Retained Earnings for the
years ended December 31, 2001, 2000 and 1999                43

Consolidated Balance Sheets as of December 31, 2001 and     44
2000

Consolidated Statements of Cash Flows for the years ended
December 31, 2001, 2000 and 1999                          45-46

Notes to Consolidated Financial Statements                  47

Selected Consolidated Quarterly Financial Data              16
(Unaudited)

Report of Independent Accountants                           75
2. Financial Statement Schedules:

Schedule II-Valuation and Qualifying accounts for the
years ended December 31, 2001, 2000 and 1999                91

</TABLE>
3. Exhibits:

Refer to the exhibits listing beginning on the following page.

(b) Reports on Form 8-K:

  None
<TABLE>
<CAPTION>
<S>           <C>
Filed herewith:

 Exhibit 21.1 Subsidiaries of the Registrant

 Exhibit 23.1 Consent of PricewaterhouseCoopers LLP

                      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         Employment Agreement between Thomas J. May and
             NSTAR dated May 11, 1999 (Incorporated by reference
             to Annex A to the Joint Proxy Statement/Prospectus
             in Part I of the Registration Statement of NSTAR on
             Form S-4, File No. 333-78285).

10.6         Change in Control Agreement between NSTAR and
             Thomas J. May dated May 11, 1999 (NSTAR Form 10-K/A
             for the year ended December 31, 1999, File No. 1-
             14768).

10.7         NSTAR Deferred Compensation Plan (Restated
             Effective August 25, 1999) (NSTAR Form 10-K/A for
             the year ended December 31, 1999, File No. 1-
             14768).

10.8         NSTAR 1997 Share Incentive Plan, as amended 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).

10.9         Amended and Restated Change in Control Agreement
             between James J. Judge and NSTAR, November 1, 2001.
             (Filed herewith)

10.10        NSTAR Trustees' Deferred Plan (Restated Effective
             August 25, 1999), dated October 20, 2000 (NSTAR
             Form 10-Q for the quarter ended September 30, 2000,
             File No. 1-14768).

10.11        Master Trust Agreement between NSTAR and State
             Street Bank and Trust Company (Rabbi Trust), dated
             August 25, 1999 (NSTAR Form 10-Q for the quarter
             ended September 30, 2000, File No. 1-14768).

10.12        Amended and Restated Change in Control Agreement
             between Douglas S. Horan and NSTAR dated November
             1, 2001 (Filed herewith).

10.13        Amended and Restated Change in Control Agreement
             between Joseph R. Nolan, Jr. and NSTAR dated
             November 1, 2001 (Filed herewith).

10.14        Amended and Restated Change in Control Agreement
             between Eugene J. Zimon and NSTAR dated November 1,
             2001 (Filed herewith).

10.15        Amended and Restated Change in Control Agreement
             between Werner J. Schweiger and NSTAR dated March
             1, 2002 (Filed herewith).


Exhibit 99   Additional Exhibits

99.1         Annual Reports on Form 11-K for certain employee
             savings plans for the years ended December 31,
             2000, 1999, 1998 and 1997, dated June 29, 2001,
             June 23, 2000, June 25, 1999 and June 25, 1998,
             respectively, File No. 1-14768


                         BEC Energy and Subsidiaries

Exhibit 3    Articles of Incorporation and By-Laws

3.1          Boston Edison Restated Articles of Organization
             (Form 10-Q for the quarter ended June 30, 1994,
             File No. 1-2301).

3.2          Boston Edison Company Bylaws April 19, 1977, as
             amended January 22, 1987, January 28, 1988, May 28,
             1988, and November 22, 1989 (Form 10-Q for the
             quarter ended June 30, 1990, File No. 1-2301).

Exhibit 4    Instruments Defining the Rights of Security
             Holders, Including Indentures

4.10         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).

4.25         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

10.12        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         Annual Reports on Form 11-K for certain employee
             savings plans for the years ended December 31, 1996
             and 1995 dated June 26, 1997 and June 27, 1996
             respectively, (File No. 1-2301).

                         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 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:

10.1.7.1     First through Fifth Amendments to 10.1.7 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).

10.1.7.2     Sixth through Eleventh Amendments to 10.1.7 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).

10.1.7.3     Twelfth through Fourteenth Amendments to 10.1.7 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).

10.1.7.4     Fifteenth and Sixteenth Amendments to 10.1.7 as
             amended April 27, 1984 and June 15, 1984,
             respectively (Exhibit 1 to the CEC Form 10-Q (June
             1984), File No. 2-30057).

10.1.7.5     Seventeenth Amendment to 10.1.7 as amended March 8,
             1985 (Exhibit 1 to the CEC Form 10-Q (March 1985),
             File No. 2-30057).

10.1.7.6     Eighteenth Amendment to 10.1.7 as amended March 14,
             1986 (Exhibit 1 to the CEC Form 10-Q (March 1986),
             File No. 2-30057).

10.1.7.7     Nineteenth Amendment to 10.1.7 as amended May 1,
             1986 (Exhibit 1 to the CEC Form 10-Q (June 1986),
             File No. 2-30057).

10.1.7.8     Twentieth Amendment to 10.1.7 as amended September
             19, 1986 (Exhibit 1 to the CEC 1986 Form 10-K, File
             No. 2-30057).

10.1.7.9     Twenty-First Amendment to 10.1.7 as amended
             November 12, 1987 (Exhibit 1 to the CEC 1987 Form
             10-K, File No. 2-30057).

10.1.7.10    Settlement Agreement and Twenty-Second Amendment to
             10.1.7, both dated January 13, 1989 (Exhibit 4 to
             the CEC 1988 Form 10-K, File No. 2-30057).

10.1.8       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).

10.1.9       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).

10.1.10      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).

10.1.11      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).

10.1.11.1    Amendment to 10.1.11 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).

10.1.12      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).

10.1.12.1    Amendment No. 2 to 10.1.12 as amended November 1,
             1982 (Exhibit 5 to the CE Form 10-Q (June 1984),
             File No. 2-7749).

10.1.12.2    Amendment No. 3 to 10.1.12 as amended January 1,
             1986 (Exhibit 2 to the CE 1986 Form 10-K, File No.
             2-7749).

10.1.13      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).

10.1.14      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).

10.1.14.1    Amendment to 10.1.14 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).

10.1.15      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).

10.1.15.1    Amendment No. 3 to 10.1.15 (Exhibit 2 to the CE
             Form 10-Q (June 1986), File No. 2-7749).

10.1.16      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).

10.1.17      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).

10.1.17.1    Amendatory Agreement No. 3 to 10.1.17 as amended
             June 1, 1990, among certain NEPOOL utilities
             (Exhibit 1 to the CEC Form 10-Q (September 1990),
             File No. 2-30057).

10.1.18      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).

10.1.19      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).

10.1.20      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).

10.1.21      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).

10.1.21.1    First, Second and Third Amendments to 10.1.21 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).

10.1.21.2    Fifth, Sixth and Seventh Amendments to 10.1.21 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).

10.1.21.3    Fourth and Eighth Amendments to 10.1.21 as amended
             July 1, 1987 and August 1, 1988, respectively
             (Exhibit 3 to the CEC Form 10-Q (September 1988),
             File No. 2-30057).

10.1.21.4    Ninth and Tenth Amendments to 10.1.21 as amended
             November 1, 1988 and January 15, 1989, respectively
             (Exhibit 2 to the CEC 1988 Form 10-K, File No. 2-
             30057).

10.1.21.5    Eleventh Amendment to 10.1.21 as amended November
             1, 1989 (Exhibit 4 to the CEC 1989 Form 10-K, File
             No. 2-30057).

10.1.21.6    Twelfth Amendment to 10.1.21 as amended April 1,
             1990 (Exhibit 1 to the CEC Form 10-Q (June 1990),
             File No. 2-30057).

10.1.22      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).

10.1.23      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).

10.1.24      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).

10.1.25      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).

10.1.25.1    Amendment No. 1 to 10.1.25 dated May 1, 1986
             (Exhibit 6 to the CEC Form 10-Q (March 1987), File
             No. 2-30057).

10.1.25.2    Amendment No. 2 to 10.1.25 as amended September 1,
             1987 (Exhibit 3 to the CEC Form 10-Q (September
             1987), File No. 2-30057).

10.1.26      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).

10.1.26.1    Amendments Nos. 1 and 2 to 10.1.26 as amended May
             1, 1986 and February 1, 1987, respectively (Exhibit
             5 to the CEC Form 10-Q (March 1987), File No. 2-
             30057).

10.1.26.2    Amendments Nos. 3 and 4 to 10.1.26 as amended June
             1, 1987 and September 1, 1987, respectively
             (Exhibit 5 to the CEC Form 10-Q (September 1987),
             File No. 2-30057).

10.1.27      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).

10.1.28      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).

10.1.29      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).

10.1.29.1    Power Sales Agreement to 10.1.29 for all capacity
             and related energy produced, dated October 31, 1985
             (Exhibit 2 to the CE 1985 Form 10-K, File No. 2-
             7749).

10.1.29.2    Amendment to 10.1.29 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).

10.1.29.3    Amendment to 10.1.29 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).

10.1.30      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).

10.1.30.1    First Amendment to 10.1.30 as amended August 15,
             1988 (Exhibit 1 to the CE Form 10-Q (September
             1988), File No. 2-7749).

10.1.30.2    Second Amendment to 10.1.30 as amended January 1,
             1989 (Exhibit 2 to the CE 1988 Form 10-K, File No.
             2-7749).

10.1.30.3    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).

10.1.30.4    Amendment to 10.1.30.3 as amended January 1, 1989
             (Exhibit 3 to the CE 1988 Form 10-K, File No. 2-
             7749).

10.1.31      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).

10.1.31.1    Second Amendment, dated June 23, 1994, to 10.1.31
             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).

10.1.32      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).

10.1.33      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).

10.1.33.1    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).

10.1.33.2    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).


10.1.33.3    First Amendment, dated November 7, 1994, to 10.1.33
             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).

10.1.33.4    First Amendment, dated November 7, 1994, to
             10.1.33.2 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       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).

10.3.1.1     Thirteenth Amendment to 10.3.1 as amended September
             1, 1981 (Refiled as Exhibit 3 to the Parent's 1991
             Form 10-K, File No. 1-7316).

10.3.1.2     Fourteenth through Twentieth Amendments to 10.3.1
             as amended December 1, 1981, June 1, 1982, June 15,
             1983, October 1, 1983, August 1, 1985, August 15,
             1985 and September 1, 1985, respectively (Exhibit 4
             to the CES Form 10-Q (September 1985), File No. 1-
             7316).

10.3.1.3     Twenty-first Amendment to 10.3.1 as amended to
             January 1, 1986 (Exhibit 1 to the CES Form 10-Q
             (March 1986), File No. 1-7316).

10.3.1.4     Twenty-second Amendment to 10.3.1 as amended to
             September 1, 1986 (Exhibit 1 to the CES Form 10-Q
             (September 1986), File No. 1-7316).

10.3.1.5     Twenty-third Amendment to 10.3.1 as amended to
             April 30, 1987 (Exhibit 1 to the CES Form 10-Q
             (June 1987), File No. 1-7316).

10.3.1.6     Twenty-fourth Amendment to 10.3.1 as amended March
             1, 1988 (Exhibit 1 to the CES Form 10-Q (March
             1989), File No. 1-7316).

10.3.1.7     Twenty-fifth Amendment to 10.3.1. as amended to May
             1, 1988 (Exhibit 1 to the CES Form 10-Q (March
             1988), File No. 1-7316).

10.3.1.8     Twenty-sixth Agreement to 10.3.1 as amended March
             15, 1989 (Exhibit 1 to the CES Form 10-Q (March
             1989), File No. 1-7316).

10.3.1.9     Twenty-seventh Agreement to 10.3.1 as amended
             October 1, 1990 (Exhibit 3 to the CES 1990 Form 10-
             K, File No. 1-7316).

10.3.1.10    Twenty-eighth Agreement to 10.3.1 as amended
             September 15, 1992 (Exhibit 1 to the CES Form 10-Q
             (September 1994), File No. 1-7316).

10.3.1.11    Twenty-ninth Agreement to 10.3.1 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).
</TABLE>

<TABLE>
<CAPTION>

                                                      SCHEDULE II

                VALUATION AND QUALIFYING ACCOUNTS

      FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 and 1999

                     (Dollars in Thousands)
<S>                           <C>            <C>        <C>       <C>          <C>
                                                  Additions         Deductions
                               Balance at    Provisions                          Balance
                                Beginning    Charged to              Accounts     at End
Description                      of Year     Operations Recoveries  Written off   of Year
Year Ended December 31,2001
Allowance for Doubtful Accounts   $28,309     $ 21,815    $ 4,130     $ 24,491    $29,763

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

(a) The beginning balance includes $5,091,000 that relates to
  COM/Energy's reserve balance at the merger date of August
  25, 1999.
</TABLE>

<TABLE>
<CAPTION>
FORM 10-K                           NSTAR
                  DECEMBER 31, 2001


                           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.
<S>                             <C>
                                       NSTAR
                                      (Registrant)


Date: March 28, 2002                  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 28th day of March 2002.

           Signature              Title


/s/      Thomas J.  May           Chairman of the Board,
                                  President and Chief
                                  Executive Officer

           Thomas J. May


/s/        R. J. Weafer, Jr.        Vice President, Controller
                                    and Chief Accounting
                                    Officer
        Robert J. Weafer, Jr.

/s/       Sheldon A.  Buckler      Trustee

      Sheldon A. Buckler

/s/       G. L.  Countryman        Trustee

      Gary L. Countryman

                                   Trustee


     Thomas G. Dignan, Jr.


/s/    Charles K.  Gifford         Trustee

      Charles K. Gifford

           Signature               Title


/s/    Matina S. Horner           Trustee



       Matina S. Horner


/s/   Franklin M.  Hundley        Trustee


      Franklin M. Hundley


/s/   Paul A. La Camera           Trustee


       Paul A. La Camera


/s/     Thomas J. May            Trustee


         Thomas J. May


/s/      Sherry H. Penney        Trustee



       Sherry H. Penney


/s/       G. L. Wilson           Trustee


       Gerald L. Wilson

  </TABLE>