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UNITED STATES SECURITIES AND

EXCHANGE COMMISSION

Washington, D.C. 20549



FORM 10-K



|x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|- | ------------------------------------------------------------------------------------



For the fiscal year ended December 31, 2004



or



| ̈ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|- | ----------------------------------------------------------------------------------------



For the transition period from
                     to



Commission file number 1-14768



NSTAR

(Exact name of registrant as specified in its charter)



|                                                               |  |                                     
|-------------------------------------------------------------- |  | ------------------------------------
|Massachusetts                                                  |  | 04-3466300                          
|(State or other jurisdiction of incorporation or organization) |  | (IRS Employer Identification Number)
|                                                               | 
|800 Boylston Street, Boston, Massachusetts                     |  | 02199                               
|(Address of principal executive offices)                       |  | (Zip code)                          



(617) 424-2000

(Registrants telephone number, including area code)



Securities registered pursuant to Section 12(b) of the Act:



|                                      |  |                                              
|------------------------------------- |  | ---------------------------------------------
|Title of each class                   |  | Name of each exchange on which registered    
|Common Shares, Par Value $1 per share |  | New York Stock Exchange Boston Stock Exchange



Securities
registered pursuant to Section 12(g) of the Act: None



Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.



x  Yes ̈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 the registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.   x



Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).



x  Yes ̈No



The aggregate
market value of the 53,118,873 shares of voting stock of the registrant held by non-affiliates of the registrant, computed as the average of the high and low market prices of the common shares as reported on the New York Stock Exchange consolidated
transaction reporting system for NSTAR Common Shares as of the last business day of the registrants most recently completed second fiscal quarter: $2,543,331,639.



Indicate the number of shares outstanding of each of the registrants classes of common stock, as of the latest
practicable date:



|                            |  |                                 
|--------------------------- |  | --------------------------------
|Class                       |  | Outstanding at February 18, 2005
|Common Shares, $1 par value |  | 53,336,360 Shares               



Documents
Incorporated by Reference



Sections of NSTARs Definitive Proxy
Statement for the 2005 Annual Meeting of Shareholders to be held on April 28, 2005 are incorporated by reference into Parts I and III of this Form 10-K.



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NSTAR



Form 10-K Annual Report -
December 31, 2004



|           |  |                                                                                                              |  |     
|---------- |  | ------------------------------------------------------------------------------------------------------------ |  | ----
|           |  |                                                                                                              |  | Page
|           |  | Part I                                                                                                       |  |     
|           |  |                                                                                                             
|Item 1.    |  | Business                                                                                                     |  | 2   
|Item 2.    |  | Properties                                                                                                   |  | 9   
|Item 3.    |  | Legal Proceedings                                                                                            |  | 10  
|Item 4.    |  | Submission of Matters to a Vote of Security Holders                                                          |  | 10  
|Item 4A.   |  | Executive Officers of the Registrant                                                                         |  | 10  
|           |  |                                                                                                             
|           |  | Part II                                                                                                      |  |     
|           |  |                                                                                                             
|Item 5.    |  | Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |  | 11  
|Item 6.    |  | Selected Consolidated Financial Data                                                                         |  | 12  
|Item 7.    |  | Managements Discussion and Analysis of Financial Condition and Results of Operations                        |  | 14  
|Item 7A.   |  | Quantitative and Qualitative Disclosures About Market Risk                                                   |  | 44  
|Item 8.    |  | Financial Statements and Supplementary Data                                                                  |  | 45  
|Item 9.    |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure                         |  | 84  
|Item 9A.   |  | Controls and Procedures                                                                                      |  | 84  
|Item 9B.   |  | Other Information                                                                                            |  | 84  
|           |  |                                                                                                             
|           |  | Part III                                                                                                     |  |     
|           |  |                                                                                                             
|Item 10.   |  | Trustees and Executive Officers of the Registrant                                                            |  | 85  
|Item 11.   |  | Executive Compensation                                                                                       |  | 85  
|Item 12.   |  | Security Ownership of Certain Beneficial Owners and Management                                               |  | 85  
|Item 13.   |  | Certain Relationships and Related Transactions                                                               |  | 85  
|Item 14.   |  | Principal Accountant Fees and Services                                                                       |  | 85  
|           |  |                                                                                                             
|           |  | Part IV                                                                                                      |  |     
|           |  |                                                                                                             
|Item 15.   |  | Exhibits and Financial Statement Schedules                                                                   |  | 86  
|           | 
|Signatures |  | 91                                                                                                          



Important
Shareholder Information



NSTAR files its Forms 10-K, 10-Q and 8-K reports,
proxy statements and other information with the Securities and Exchange Commission (SEC). You may access materials NSTAR has filed with the SEC on the SECs website at www.sec.gov. In addition, NSTARs Board of Trustees has various
committees, including an Audit, Finance and Risk Management Committee, an Executive Personnel Committee and a Board Governance and Nominating Committee. The Board also has a standing Executive Committee. The Board has adopted the NSTAR Board of
Trustees Corporate Guidelines on Significant Corporate Governance Issues, a Code of Ethics for the Principal Executive Officer, General Counsel, and Senior Financial Officers, and a Code of Ethics and Business Conduct for Directors, Officers and
Employees. NSTARs SEC filings and Corporate Governance documents, including charters, guidelines and codes, and any amendments to such charters, guidelines and codes that are applicable to NSTARs executive officers, senior financial
officers or trustees can be accessed free of charge on NSTARs website at www.nstaronline.com. Copies of NSTARs SEC filings may also be obtained by writing or calling NSTARs Investor Relations Department at the address or phone
number on the cover of this Form 10-K.



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Part I



|Item 1. | Business
|------- | --------



(a) General Development of Business



NSTAR (or the Company) is a holding company engaged through its subsidiaries in the energy delivery business serving approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric distribution customers
in 81 communities and approximately 300,000 natural gas distribution customers in 51 communities. NSTAR was created in 1999 in connection with the merger of BEC Energy (BEC) and Commonwealth Energy System (COM/Energy). 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 collectively operate as NSTAR Electric. Reference in this report to NSTAR shall mean the registrant NSTAR or NSTAR and its subsidiaries as the context requires. Reference
in this report to NSTAR Electric shall mean Boston Edison, ComElectric and Cambridge Electric together. NSTARs non-utility, unregulated operations include district energy operations (Advanced Energy Systems, Inc. and NSTAR Steam
Corporation), telecommunications operations (NSTAR Communications, Inc. (NSTAR Com)) and a liquefied natural gas service company (Hopkinton LNG Corp.). Utility operations accounted for approximately 96% of consolidated operating revenues in 2004,
2003 and 2002.



(b) Financial Information about Industry Segments



NSTARs principal operating segments are the electric and natural
gas utility operations that provide energy delivery services in 107 cities and towns in Massachusetts and its unregulated operations. Refer to Note N of the accompanying Consolidated Financial Statements in Item 8, Financial Statements
and Supplementary Data for specific financial information related to NSTARs electric utility, gas utility and unregulated operating segments.



(c) Narrative Description of Business



Principal Products and Services



NSTAR Electric



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



NSTAR Electrics operating revenues and energy sales percentages by customer class for the years 2004, 2003 and 2002 consisted of the following:



|                             |  |              |   |  |                    |   |  |      |   |  |      |   |  |      |   |  |      |  
|---------------------------- |  | ------------ | - |  | ------------------ | - |  | ---- | - |  | ---- | - |  | ---- | - |  | ---- | -
|                             |  | Revenues ($) |   |  | Energy Sales (MWH) |  
|                             |  | 2004         |   |  | 2003               |   |  | 2002 |   |  | 2004 |   |  | 2003 |   |  | 2002 |  
|Retail:                      |  |              |   |  |                    |   |  |      |   |  |      |   |  |      |   |  |      |  
|Commercial                   |  | 54           | % |  | 54                 | % |  | 52   | % |  | 59   | % |  | 59   | % |  | 56   | %
|Residential                  |  | 39           | % |  | 38                 | % |  | 37   | % |  | 31   | % |  | 31   | % |  | 29   | %
|Industrial and other         |  | 6            | % |  | 7                  | % |  | 8    | % |  | 9    | % |  | 9    | % |  | 10   | %
|Wholesale and contract sales |  | 1            | % |  | 1                  | % |  | 3    | % |  | 1    | % |  | 1    | % |  | 5    | %



Retail Electric Rates



Retail electric delivery rates are established
by the Massachusetts Department of Telecommunications and Energy (MDTE) and are composed of:



| |  |  | distribution charges, which include a fixed customer charge and energy and demand charges (to collect the costs of building and expanding the infrastructure to deliver power to its
destination, as well as ongoing operating and maintenance costs),
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | a transition charge (to collect costs primarily for previously held investments in generating plants and costs related to above market power contracts),
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | a transmission charge (to collect the cost of moving the electricity over high voltage lines from generating plants to substations located within NSTARs service area),
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | an energy conservation charge (an MDTE - mandated charge to collect costs for demand-side management programs) and
| | - |  | ------------------------------------------------------------------------------------------------------------------



| |  |  | a renewable energy charge (an MDTE - mandated charge to collect the cost to support the development and promotion of renewable energy projects).
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------



Beginning in 2004, rates applicable to NSTARs regulated electric utilities were
increased to reflect the implementation of a rate mechanism to collect pension and postretirement benefit obligations other than pension (PBOP) costs on a fully reconciling basis. Refer to the accompanying Consolidated Financial Statements, Note
I, for more detail.



Electric distribution companies in Massachusetts are
required to obtain and resell power to retail customers through either standard offer or default service for those who choose not to buy energy from a competitive energy supplier. Standard offer service will end on February 28, 2005. Therefore,
effective March 1, 2005, all customers who have not chosen to receive service from a competitive supplier will be provided default service, which will be designated basic service thereafter. Default service rates are reset every six months (every
three months for large commercial and industrial customers). The price of default service is intended to reflect the average competitive market price for power. As of December 31, 2004, 2003 and 2002, customers of NSTAR Electric had approximately
24%, 26% and 27%, respectively, of their load requirements provided by competitive suppliers.



Sources and Availability of Electric Power Supply



For default service power supply, NSTAR Electric makes periodic market solicitations consistent with provisions of the Restructuring Act and
MDTE orders. During 2004, NSTAR Electric entered into a short-term power purchase agreement to meet its entire default service supply obligation, other than to its largest customers, for the period January 1, 2005 through June 30, 2005 and for 50%
of its obligation, other than to these large customers, for the second-half of 2005. NSTAR Electric has entered into a short-term power purchase agreement to meet its entire default service supply obligation for large customers through March 2005. A
Request for Proposals will be issued quarterly in 2005 for the remainder of the obligation for large customers and semi-annually for non-large customers in accordance with MDTE requirements. For 2004, NSTAR Electric entered into agreements ranging
in length from three to twelve-months effective January 1, 2004 through December 31, 2004 with suppliers to provide full default service energy and ancillary service requirements at contract rates approved by the MDTE.



For standard offer service power supply, NSTAR Electric has contracted with third party
suppliers to provide 100% of its obligation through February 28, 2005, the date when standard offer service ends and all load migrates to either default service or competitive supply. NSTAR Electric is fully recovering its payments to suppliers
through MDTE-approved rates billed to customers. NSTAR Electric, during 2004, entered into several agreements to buy-out or restructure certain of its long-term power purchase contracts. Refer to the accompanying Consolidated Financial Statements,
Note O, for more detail.



NSTAR Electrics load for 2004 reached a
peak demand of 4,254 megawatts (MW) on August 30, which was 3.6% less than the all-time peak demand level of 4,415 MW established in 2002.



Wholesale Market Rule Changes



Standard Market Design (SMD)



Pursuant to orders issued by the Federal Energy Regulatory Commission (FERC), wholesale electric markets in New England have been operating under SMD since March 1, 2003.
Under SMD, generators are dispatched on a



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least cost basis until the generation dispatched equals the amount of energy required. The clearing price is set at the price of the next available megawatt
of generation and is paid to all dispatched generators. SMD provides an additional market in which wholesale power costs can be hedged a day in advance through binding financial commitments. Also, under SMD, wholesale power clearing prices vary by
location, called load zones, with prices in load zones with less efficient generation being higher than in load zones with more efficient generation during periods when transmission constraints prevent the lower cost generation from moving from one
load zone to another. This mechanism is known as Locational Marginal Pricing (LMP). NSTAR Electrics service territory covers two of the eight load zones in New England: Northeastern MA (NEMA) and Southeastern MA (SEMA). NEMA is
import-constrained and SEMA is export-constrained. The majority of NSTARs customers are in the NEMA load zone. During periods of transmission constraints, NEMA has a higher LMP than SEMA. As part of SMD, load-serving entities, like NSTAR
Electric, were granted proceeds from the auction of financial transmission rights that is conducted by the Independent System Operator (ISO-NE). NSTAR Electric uses these proceeds to mitigate costs to customers.



Locational Installed Capacity (LICAP)



The ISO-NE has proposed a new market rule designed to compensate wholesale generators for
their capacity, called LICAP. The proposed LICAP rules require electric load serving entities (LSE), like NSTAR Electric, to procure capacity within the zones where load is served. The current market structure allows capacity, located anywhere in
New England, to count towards a LSEs obligation, regardless of load zone. At this point, it appears likely that NSTARs new 345kV transmission project will reduce transmission constraints causing capacity prices between NEMA and SEMA to
converge, which could ultimately render this locational aspect of LICAP a non-factor for NSTAR customers. (Refer to Capital Expenditures and Financings section for more information on NSTARs 345kV transmission project). However,
since proposed market rules require that a certain amount of capacity be procured in the NEMA zone and, depending on how many market rules are finally adopted, these requirements could impact pricing for capacity in the NEMA zone. Additionally, much
of the capacity in the NEMA zone has issued notice of its intent to file with the FERC for cost of service type agreements called Reliability Must Run agreements for the recovery of their costs prior to the implementation of LICAP. The proposed
LICAP rules will impact overall capacity pricing levels in New England. Since the New England market as a whole is currently in a surplus position, capacity trades at a relatively low price. One of the goals of LICAP is to provide a higher level of
compensation to generators than what is currently being earned in this surplus market. This will likely increase the price of power to NSTARs customers. The proposed LICAP market rules are contentious and are currently being litigated at FERC
and in the courts. A final FERC ruling on the issue is expected in 2005 and the current schedule calls for an implementation date of January 1, 2006. Until these rules are finalized and approved, NSTAR cannot predict the actual impact these changes
will have on NSTAR Electric and its customers.



Regional Transmission Organization (RTO)



On March 24, 2004, the FERC
decided to schedule hearings for a joint return on equity (ROE) filing made by participating New England Transmission Owners, including NSTAR Electric. The filing requested an increase in the base ROE component of the regional and local transmission
rates, to be provided under the Regional Transmission Organization for New England (RTO-NE) open access transmission tariff (OATT), to a single ROE of 12.8% for all regional and local transmission rates. Presently, transmission service in New
England is provided under a two-tier structure, with the potential for the ROE for local service to be different than for regional service for the same transmission provider. FERC has previously approved other RTO filings for an ROE adder of 50
basis points in regional rates as an incentive for joining an RTO for regional service. In addition, FERC has also scheduled hearings to address the proposal for an additional 100 basis points in regional rates to provide an incentive to build new
transmission facilities. The Transmission Owners maintain that sufficient equity returns are needed to elicit the necessary investments in transmission within an RTO. Settlement negotiations occurred in April 2004 before a FERC administrative law
judge and were unsuccessful. Hearings on the base ROE and 100 basis point adder began in January 2005.



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The joint ROE filing among the Transmission Owners was made in connection with the proposed formation of RTO-NE by the
Transmission Owners and ISO-NE, the present administrator of the New England Power Pool (NEPOOL) OATT, and is an important and integral component of the agreement to form an RTO for the New England region. On November 3, 2004, the FERC accepted a
settlement agreement among NEPOOL, ISO-NE and the New England Transmission Owners, including NSTAR Electric, which resolved many issues left outstanding from FERCs March 2004 Order conditionally approving the formation of RTO-NE. The November
3rdOrder also provided clarification of certain aspects of the March 2004 Order regarding the Transmission
Owners request for an increase in the base return on equity component of the regional and local transmission rates. This clarification narrowed the scope of issues to be addressed during the January 2005 hearings on the base ROE proposal and
the Transmission Owners proposal for an additional 100 basis points in regional rates to provide an incentive to build new transmission facilities. Finally, the November 3rdOrder required the satisfaction of several ministerial conditions before ISO-NE could begin to operate as an RTO. ISO-NE and the Transmission Owners have
since satisfied such conditions and provided 30 days notice to FERC and NEPOOL that on February 1, 2005, ISO-NE would begin to operate as an RTO. Effective February 1, 2005, the ISO-NE is an independent entity, without a financial interest in the
regions marketplace, having operating authority over the New England transmission grid and the responsibility to make impartial decisions on the development and implementation of market rules. The ISO-NE operates under a series of contractual
arrangements that define its functions and responsibilities, including a Transmission Operating Agreement, which governs the relationship between the owners of transmission facilities, such as NSTAR Electric and the ISO-NE, as the operator of the
New England transmission grid. Separate agreements govern the operation of the spot power and related markets, the ISO-NEs interactions with market participants and merchant transmission facilities. NSTARs management cannot estimate the
impact of the RTO on the Company.



NSTAR Gas



NSTAR Gas distributes natural gas to approximately 300,000 customers in 51 communities in
central and eastern Massachusetts covering 1,067 square miles and having an aggregate population of 1.2 million. Twenty-five of these communities are also served with electricity by NSTAR Electric. Some of the larger communities served by NSTAR Gas
include Cambridge, Somerville, New Bedford, Plymouth, Worcester, Framingham, Dedham and the Hyde Park area of Boston.



NSTAR Gas operating revenues and energy sales percentages by customer class for the years 2004, 2003 and 2002, consisted of the following:



|                              |  |              |   |  |                       |   |  |      |   |  |      |   |  |      |   |  |      |  
|----------------------------- |  | ------------ | - |  | --------------------- | - |  | ---- | - |  | ---- | - |  | ---- | - |  | ---- | -
|                              |  | Revenues ($) |   |  | Energy Sales (therms) |  
|                              |  | 2004         |   |  | 2003                  |   |  | 2002 |   |  | 2004 |   |  | 2003 |   |  | 2002 |  
|Gas Sales and Transportation: |  |              |   |  |                       |   |  |      |   |  |      |   |  |      |   |  |      |  
|Residential                   |  | 61           | % |  | 61                    | % |  | 64   | % |  | 45   | % |  | 47   | % |  | 42   | %
|Commercial                    |  | 25           | % |  | 25                    | % |  | 21   | % |  | 33   | % |  | 33   | % |  | 34   | %
|Industrial and other          |  | 9            | % |  | 10                    | % |  | 9    | % |  | 17   | % |  | 17   | % |  | 19   | %
|Off-System and contract sales |  | 5            | % |  | 4                     | % |  | 6    | % |  | 5    | % |  | 3    | % |  | 5    | %



Natural Gas Rates



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



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supply costs from firm sales customers and default service customers. The LDAC provides for the recovery of certain costs applicable to both sales and
transportation customers. The CGAC is filed semi-annually for approval by the MDTE. The LDAC is filed annually for approval. In addition, NSTAR Gas is required to file interim changes to its CGAC factor when the actual costs of gas supply vary from
projections by more than 5%.



Beginning in 2004, NSTAR Gas rates were
increased to reflect the implementation of a rate mechanism to collect pension and PBOP costs on a fully reconciling basis. Refer to the Consolidated Financial Statements, Note I, for more detail.



Effective November 1, 2000, the MDTE approved regulations that expand the choice of gas
suppliers to all customers of local gas distribution companies (LDCs) such as NSTAR Gas. The regulations established a five-year transition period and a three-year review of market conditions to determine whether the supply market has become
sufficiently competitive to warrant removal or modification of the LDCs service obligation with respect to planning and procurement. To meet the requirements of the regulations, NSTAR Gas has modified its billing, customer and gas supply
systems to accommodate full retail choice. The MDTE previously had approved the compliance process submitted by NSTAR Gas and other LDCs that implement the unbundling of retail gas services to all customers. Among the important provisions are:
setting the LDC as the default service provider, certification of competitive suppliers/marketers, extension of the MDTEs consumer protection rules to residential customers taking competitive service, requirement for LDCs to provide
suppliers/marketers with customers usage data, and requirement for suppliers/marketers to disclose service terms to potential customers. The MDTE has also ruled on requiring the mandatory assignment of the LDCs upstream pipeline and storage
capacity and downstream peaking capacity to customers who elect a competitive gas supply. This eliminates potential stranded cost exposure for the LDCs for the five-year transition period. In January 2004, the MDTE opened a new docket to determine
whether the upstream capacity market is sufficiently competitive to warrant the voluntary assignment of interstate pipeline capacity to other entities. Such a determination could modify the mandatory approach to capacity assignment established in
November 2000. NSTAR cannot predict or anticipate the outcome of this process or its impact on NSTAR or its customers.



Gas Supply, Transportation and Storage



NSTAR Gas maintains a flexible resource portfolio consisting of gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking
services.



NSTAR Gas purchases transportation, storage and balancing services
from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that bring gas from major producing regions in the U.S., Gulf of Mexico and Canada to the final delivery points in the NSTAR Gas service
area. NSTAR Gas purchases all of its gas supply from third-party vendors, primarily under firm contracts with terms of less than one year. The vendors vary from small independent marketers to major gas and oil producers. Based on its firm pipeline
transportation capacity entitlements, NSTAR Gas contracts for up to 140,309 million British thermal units (MMbtu) per day of domestic production. In addition, NSTAR Gas has an agreement for up to 4,500 MMbtu per day of Canadian supplies.



In addition to the firm transportation and gas supplies mentioned above, NSTAR Gas
utilizes contracts for underground storage and liquefied natural gas (LNG) facilities to meet its winter peaking demands. The LNG facilities, described below, are located within NSTAR Gas distribution system and are used to liquefy and store
pipeline gas during the warmer months for use during the heating season. The underground storage contracts are a combination of existing and new agreements that are the result of FERC Order 636 service unbundling. During the summer injection season,
excess pipeline capacity is used to deliver and store gas in market area storage facilities, located in the New York and Pennsylvania region. Stored gas is withdrawn during the winter season to supplement pipeline supplies in order to meet firm
heating demand. NSTAR Gas has firm storage capacity entitlements of nearly 8.0 billion cubic feet (Bcf).



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



In addition, Hopkinton owns a satellite vaporization plant and two
above-ground cryogenic storage tanks located in Acushnet, Massachusetts with an aggregate capacity of 0.5 Bcf of natural gas that are filled with LNG trucked from the Hopkinton facility or purchased from third parties.



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



Franchises



Through their charters, which are unlimited in time, NSTAR Electric and NSTAR Gas have the right to engage in the business of delivering 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 lines and gas distribution pipelines are obtained from municipal and other state authorities who, 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. Under Massachusetts law, no other entity may provide electric or gas
delivery service to retail customers within NSTARs territory without the written consent of NSTAR Electric and/or NSTAR Gas. This consent must be filed with the MDTE and the municipality so affected.



Unregulated Operations



NSTARs unregulated operations segment engages in businesses that include district energy operations, telecommunications and liquefied
natural gas service. District energy operations are principally provided through its Advanced Energy Systems, Inc. (AES) subsidiary that generates chilled water, steam and electricity for use by hospitals and teaching facilities located in
Bostons Longwood Medical Area. AES expanded its Medical Area Total Energy Plant (MATEP) facility in 2003 to provide additional capacity. NSTAR Steam also supplies steam to customers in Cambridge. Telecommunications services are provided
through NSTAR Com, which installs, owns, operates and maintains a wholesale transport network for other telecommunications service providers in the metropolitan Boston area to deliver voice, video, data and internet services to customers. Liquefied
natural gas service is provided by Hopkinton LNG Corp. Revenues earned from NSTARs unregulated operations account for approximately 4% of consolidated operating revenues in 2004, 2003 and 2002.



RCN Joint Venture, Investment Conversion and Abandonment



Beginning in 1997, NSTAR Com participated in a telecommunications venture
with RCN Telecom Services, Inc. of Massachusetts, a subsidiary of RCN Corporation (RCN). As part of the Joint Venture Agreement, NSTAR Com had the option to exchange portions of its joint venture interest for common shares of RCN at specified
periods. NSTAR Com exercised this option and exchanged its entire joint venture interest for common shares of RCN over several years through 2002. As of December 31, 2002, NSTAR Com no longer participated in the joint venture but held approximately
11.6 million common shares of RCN. On December 24, 2003, NSTAR abandoned its common shares of RCN.



Regulation



NSTAR is a holding company
exempt from the provisions of the Public Utility Holding Company Act of 1935, as amended, except Section 9(c)(2) relating to SEC approval of certain acquisitions of securities of public utility or public utility holding companies.



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



Capital Expenditures and Financings



The most recent estimates of capital expenditures and long-term debt maturities for the
years 2005 through 2009 are as follows:



|                     |  |      |         |      |   |         |  |      |         |      |   |         |  |   |        
|-------------------- |  | ---- | ------- | ---- | - | ------- |  | ---- | ------- | ---- | - | ------- |  | - | -------
|(in thousands)       |  | 2005 |         | 2006 |   | 2007    |  | 2008 |         | 2009
|Capital expenditures |  | $    | 398,000 |      | $ | 313,000 |  | $    | 275,000 |      | $ | 240,000 |  | $ | 240,000
|Long-term debt       |  | $    | 149,245 |      | $ | 248,024 |  | $    | 83,218  |      | $ | 85,629  |  | $ | 75,962 



Capital expenditures include costs
related to NSTARs 345kV transmission project that in the aggregate is expected to total approximately $200 million. A significant portion of these costs will be incurred in 2005 and 2006. NSTAR has obtained regulatory approval to construct a
345 kV transmission line from Stoughton, Massachusetts, a southern suburb of Boston, to South Boston in order to assure continued reliability of service and improve power import capacity in the Northeast Massachusetts area (NEMA). Construction is
set to begin in the first quarter of 2005, subject to final permitting. The entire new transmission line is anticipated to be placed in service during the summer of 2006. This project is a regional transmission investment and, as a result, the cost
will be shared by all of New England and recovered by NSTAR through wholesale and retail transmission rates.



Management continuously reviews its capital expenditure and financing programs. These programs and, therefore, the estimates included in this Form 10-K are subject to revision due to changes in regulatory
requirements, operating requirements, environmental standards, availability and cost of capital, interest rates and other assumptions. Refer to the Cautionary Statement section of Item 7, Managements Discussion and
Analysis of Financial Condition and Results of Operations.



Plant
expenditures in 2004 were approximately $313 million and consisted primarily of additions to NSTARs distribution and transmission systems. The majority of these expenditures were for system reliability and performance improvements, customer
service enhancements and capacity expansion to meet long-range growth in the NSTAR service territory.



Refer to the Liquidity and Capital Resources section of Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations for more information regarding
capital resources to fund NSTARs construction programs.



Seasonal
Nature of Business



NSTAR Electrics kilowatt-hour sales and revenues
are typically higher in the winter and summer than in the spring and fall as sales tend to vary with weather conditions. NSTAR Gas sales are positively impacted by colder weather because a substantial portion of its customer base uses natural
gas for space heating purposes. Refer to the Selected Quarterly Consolidated Financial Data section in Item 6, Selected Consolidated Financial Data for specific financial information by quarter for 2004 and 2003.



Competitive Conditions



The electric and natural gas industries, in general, 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 efficiencies and other benefits through business combinations. NSTAR operates
in this marketplace by combining the resources of its utility subsidiaries activities in the transmission and distribution of energy.



8



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Environmental Matters



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



Management believes that its facilities are in substantial compliance with currently applicable statutory and regulatory environmental requirements.



Number of Employees



As of December 31, 2004, NSTAR had approximately 3,100 employees, including approximately 2,200, or 71%, who are represented by three units
covered by separate collective bargaining contracts.



NSTARs contract
with Local 369 of the Utility Workers Union of America, AFL-CIO, which represents approximately 1,900 employees, expires on May 15, 2005. Management has begun discussions with union officials for Local 369 for a new labor contract. Approximately 250
employees, represented by Local 12004, United Steelworkers of America, AFL-CIO, have a contract that expires on March 31, 2006. Approximately 60 employees of Advanced Energy Systems MATEP subsidiary are represented by Local 877, the
International Union of Operating Engineers, AFL-CIO, under a contract that expires on September 30, 2006.



Management believes it has satisfactory relations with its employees.



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



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



|Item 2. | Properties
|------- | ----------



NSTAR Electric properties include an integrated system of distribution lines and substations, an office building and other structures such as garages and service centers that are located primarily in eastern
Massachusetts.



At December 31, 2004, the NSTAR Electric primary and secondary
transmission and distribution system consisted of approximately 20,300 circuit miles of overhead lines, approximately 9,000 circuit miles of underground lines, 258 substation facilities and approximately 1,312,000 active customer meters.



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



Cambridge Electric completed the sale of Blackstone Station in April 2003. NSTAR, through its
Canal subsidiary, sold its 3.52% ownership interest (40.5 MW of capacity) in the Seabrook Nuclear Generating Station on November 1, 2002.



NSTAR Gas principal natural gas properties consist of distribution mains, services and meters necessary to maintain reliable service to customers. At December 31,
2004, the gas system included approximately 2,950 miles of gas distribution lines, approximately 180,200 services and approximately 278,000 customer meters together with the necessary measuring and regulating equipment. In addition, Hopkinton LNG
Corp. owns a liquefaction and vaporization plant, a satellite vaporization plant and above ground cryogenic storage tanks



9



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having an aggregate storage capacity equivalent to 3.5 Bcf of natural gas. NSTAR Gas owns an office and service building in Southborough, Massachusetts,
three district office buildings and several natural gas receiving and take stations.



In 2002, NSTARs utility subsidiaries purchased a 370,000 square foot office building (the Summit) sited on 33 acres in the Boston suburb of Westwood, Massachusetts. This site is centrally located in NSTARs service area and
houses its central administrative offices including customer care, finance, human resources, sales, engineering, and information technology.



District energy operations primarily consist of AES MATEP facility located in the Longwood Medical Area of Boston. MATEP provides steam, chilled water and
electricity to over 9 million square feet of medical and teaching facilities. NSTAR Steams distribution system consists primarily of approximately 3.5 miles of steam lines utilized to provide service to customers in Cambridge, MA.



|Item 3. | Legal Proceedings
|------- | -----------------



In the normal course of its business, NSTAR and its subsidiaries are involved in certain legal matters, including civil litigation. Management is unable to fully determine a range of reasonably possible court-ordered
damages, settlement amounts, and related litigation costs (legal liabilities) that would be in excess of amounts accrued and amounts covered by insurance. Based on the information currently available, NSTAR does not believe that it is
probable that any such legal liabilities will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal liabilities that may result from changes in circumstances could have a material
impact on its results of operations, cash flows and financial condition for a reporting period.



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



There were no matters submitted to a vote of security holders during the fourth quarter of 2004.



|Item 4A. | Executive Officers of Registrant
|-------- | --------------------------------



Identification of Executive Officers



|                     |  |                                                                                                                                                                                            |  |                        
|-------------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | -----------------------
|Name of Officer      |  | Position and Business Experience                                                                                                                                                           |  | Age atDecember 31, 2004
|Thomas J. May        |  | Chairman, President (since 2002), Chief Executive Officer and a Trustee (since 1999); Director, Bank of America Corporation and Liberty Mutual Holding Company Inc.                        |  | 57                     
|                     |  |                                                                                                                                                                                           
|Douglas S. Horan     |  | Senior Vice President - Strategy, Law and Policy, Secretary and General Counsel (since 2000); formerly Senior Vice President - Strategy, Law and Policy (1999-2000).                       |  | 55                     
|                     |  |                                                                                                                                                                                           
|James J. Judge       |  | Senior Vice President, Treasurer and Chief Financial Officer (since 2000); formerly Senior Vice President and Chief Financial Officer (1999-2000).                                         |  | 48                     
|                     |  |                                                                                                                                                                                           
|Timothy R. Manning   |  | Senior Vice President - Human Resources (since 2002); formerly Vice President Human Resources (2001); Director of Employee and Labor Relations (1999-2001).                                |  | 53                     
|                     |  |                                                                                                                                                                                           
|Joseph R. Nolan, Jr. |  | Senior Vice President - Customer and Corporate Relations (since 2002); formerly Senior Vice President - Corporate Relations (2000-2002); Vice President of Government Affairs
(1999-2000). |  | 41                     



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|                      |  |                                                                                                                                                                                           |  |                        
|--------------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | -----------------------
|Name of Officer       |  | Position and Business Experience                                                                                                                                                          |  | Age atDecember 31, 2004
|                      |  |                                                                                                                                                                                          
|Werner J. Schweiger   |  | Senior Vice President - Operations (since 2002); formerly Vice President, Office of Electric Operations/Transmission and Distribution Management, Keyspan Energy Corporation
(1997-2002). |  | 45                     
|                      |  |                                                                                                                                                                                          
|Eugene J. Zimon       |  | Senior Vice President - Information Technology (since 2001); formerly Vice President, Business Development for Utilities, Oracle Corporation (2000-2001).                                 |  | 56                     
|                      |  |                                                                                                                                                                                          
|Robert J. Weafer, Jr. |  | Vice President, Controller and Chief Accounting Officer (since 1999).                                                                                                                     |  | 57                     



PART II



|Item 5. | Market for the Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
|------- | ----------------------------------------------------------------------------------------------------------------



(a) Market Information



The NSTAR Common Shares, $1 par value, are listed on the New York and Boston Stock Exchanges
under the symbol NST. NSTARs Common Shares closing market price at December 31, 2004 was $54.28 per share.



The NSTAR Common Shares high and low sales prices as reported by the New York Stock Exchange composite transaction reporting system for each of the quarters in 2004 and
2003 were as follows:



|               |  |      |       |      |   |       |  |     |       |  |   |      
|-------------- |  | ---- | ----- | ---- | - | ----- |  | --- | ----- |  | - | -----
|               |  | 2004 |       | 2003
|               |  | High |       | Low  |   | High  |  | Low
|First quarter  |  | $    | 52.85 |      | $ | 48.00 |  | $   | 46.12 |  | $ | 38.67
|Second quarter |  | $    | 52.00 |      | $ | 45.30 |  | $   | 48.00 |  | $ | 39.78
|Third quarter  |  | $    | 50.50 |      | $ | 46.01 |  | $   | 48.34 |  | $ | 43.63
|Fourth quarter |  | $    | 54.45 |      | $ | 48.17 |  | $   | 48.96 |  | $ | 45.08



In December 2004, NSTAR announced its
intention to split its common shares two-for-one, subject to market conditions and shareholder approval of an amendment to the Companys Declaration of Trust which would increase the number of NSTARs authorized common shares, at the April
28, 2005 Annual Meeting of Shareholders.



(b)
Holders



As of December 31, 2004, there were 24,653 registered holders of
NSTAR Common Shares.



(c) Dividends



Dividends declared per Common Share for each
quarter of 2004 and 2003 were as follows:



|               |  |      |       |      |   |      
|-------------- |  | ---- | ----- | ---- | - | -----
|               |  | 2004 |       | 2003
|First quarter  |  | $    | 0.555 |      | $ | 0.54 
|Second quarter |  | $    | 0.555 |      | $ | 0.54 
|Third quarter  |  | $    | 0.555 |      | $ | 0.54 
|Fourth quarter |  | $    | 0.58  |      | $ | 0.555



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##### Table of Contents

NSTAR paid common share dividends to shareholders totaling $117.9 million and $114.6 million in 2004 and 2003,
respectively.



(d) Securities authorized for
issuance under equity compensation plans



The following table provides
information about NSTARs equity compensation plans as of December 31, 2004.



|                                                       |  |                                                                     |  |                                                     |       |                                                                                         |          
|------------------------------------------------------ |  | ------------------------------------------------------------------- |  | --------------------------------------------------- | ----- | --------------------------------------------------------------------------------------- | ---------
|Plan Category                                          |  | Number of securitiesto be issued uponexercise ofoutstanding options |  | Weighted-averageexercise price ofoutstandingoptions |       | Number ofsecurities remainingavailable forfuture issuanceunder equitycompensation plans
|Equity compensation plans approved by shareholders     |  | 1,456,169                                                           |  | $                                                   | 43.45 |                                                                                         | 1,992,027
|Equity compensation plans not approved by shareholders |  |                                                                    |  |                                                     |      |                                                                                         |         
|                                                       |  |                                                                     |  |                                                     |       |                                                                                         |          
|Total                                                  |  | 1,456,169                                                           |  | $                                                   | 43.45 |                                                                                         | 1,992,027
|                                                       |  |                                                                     |  |                                                     |       |                                                                                         |          



(e)
Purchases of equity securities



Common Shares of NSTAR issued under the NSTAR
Dividend Reinvestment and Direct Common Shares Purchase Plan, the 1997 Share Incentive Plan and the NSTAR Savings Plan in connection with common share grants and the exercise of stock options may consist of newly issued shares from the Company or
shares purchased in the open market by the Company or an independent agent. During the three-month period ended December 31, 2004, the shares listed below were acquired in the open market primarily in connection with the NSTAR Savings Plan.



|         |  |                                       |  |                             |      
|-------- |  | ------------------------------------- |  | --------------------------- | -----
|         |  | Total Number ofCommon SharesPurchased |  | Average PricePaid Per Share
|October  |  | 48,700                                |  | $                           | 49.66
|November |  | 16,100                                |  | $                           | 50.79
|December |  | 14,200                                |  | $                           | 53.26



|Item 6. | Selected Consolidated Financial Data
|------- | ------------------------------------



The following table summarizes five years of selected consolidated financial data.



|                                         |  |      |           |      |   |           |  |      |           |  |      |           |   |  |   |          
|---------------------------------------- |  | ---- | --------- | ---- | - | --------- |  | ---- | --------- |  | ---- | --------- | - |  | - | ---------
|(in thousands, except per share data)    |  | 2004 |           | 2003 |   | 2002      |  | 2001 |           |  | 2000
|Operating revenues                       |  | $    | 2,954,332 |      | $ | 2,911,711 |  | $    | 2,690,625 |  | $    | 3,181,167 |   |  | $ | 2,692,198
|Net income (loss)(a)                     |  | $    | 188,481   |      | $ | 181,574   |  | $    | 161,707   |  | $    | (2,426    | ) |  | $ | 175,002  
|Earnings (loss) per common share:        |  |      |           |      |   |           |  |      |           |  |      |           |   |  |   |          
|Basic (a)                                |  | $    | 3.55      |      | $ | 3.42      |  | $    | 3.05      |  | $    | (0.05     | ) |  | $ | 3.19     
|Diluted (a)                              |  | $    | 3.51      |      | $ | 3.40      |  | $    | 3.03      |  | $    | (0.05     | ) |  | $ | 3.18     
|Total assets                             |  | $    | 7,117,229 |      | $ | 6,332,151 |  | $    | 6,338,454 |  | $    | 5,328,191 |   |  | $ | 5,547,715
|Long-term debt (b)                       |  | $    | 1,792,654 |      | $ | 1,602,402 |  | $    | 1,645,465 |  | $    | 1,377,899 |   |  | $ | 1,440,431
|Transition property securitization (b)   |  | $    | 308,748   |      | $ | 377,150   |  | $    | 445,890   |  | $    | 513,904   |   |  | $ | 584,130  
|Preferred stock of subsidiary (b)        |  | $    | 43,000    |      | $ | 43,000    |  | $    | 43,000    |  | $    | 43,000    |   |  | $ | 43,000   
|Cash dividends declared per common share |  | $    | 2.245     |      | $ | 2.175     |  | $    | 2.13      |  | $    | 2.075     |   |  | $ | 2.015    

---

|(a) | 2002 and 2001 include non-cash, after-tax charges of $17.7 million and $173.9 million, or $0.33 per share and $3.28 per basic share, respectively, related to NSTARs investment
in RCN Corporation.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

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



Selected Quarterly Consolidated Financial Data (Unaudited)



|                                          |  |                   |         |                 |   |               |  |                                     |        |  |   |     
|----------------------------------------- |  | ----------------- | ------- | --------------- | - | ------------- |  | ----------------------------------- | ------ |  | - | ----
|(in thousands, except earnings per share) |  |                   |         |                
|                                          |  | OperatingRevenues |         | OperatingIncome |   | NetIncome (a) |  | EarningsPer BasicCommon Share(a)(b)
|2004                                      |  |                   |         |                 |   |               |  |                                     |        |  |   |     
|First quarter                             |  | $                 | 809,908 |                 | $ | 87,507        |  | $                                   | 49,716 |  | $ | 0.94
|Second quarter                            |  | $                 | 649,787 |                 | $ | 73,407        |  | $                                   | 37,525 |  | $ | 0.71
|Third quarter                             |  | $                 | 781,510 |                 | $ | 101,268       |  | $                                   | 63,281 |  | $ | 1.19
|Fourth quarter                            |  | $                 | 713,127 |                 | $ | 76,146        |  | $                                   | 37,959 |  | $ | 0.71
|                                          |  |                   |         |                
|2003                                      |  |                   |         |                 |   |               |  |                                     |        |  |   |     
|First quarter                             |  | $                 | 762,932 |                 | $ | 84,601        |  | $                                   | 42,338 |  | $ | 0.80
|Second quarter                            |  | $                 | 647,029 |                 | $ | 73,261        |  | $                                   | 39,154 |  | $ | 0.74
|Third quarter                             |  | $                 | 817,333 |                 | $ | 102,299       |  | $                                   | 63,662 |  | $ | 1.20
|Fourth quarter                            |  | $                 | 684,417 |                 | $ | 72,350        |  | $                                   | 36,420 |  | $ | 0.69

---

|(a) | The fourth quarter of 2003 includes a non-cash after-tax charge of $4.5 million, or $0.08 per basic share, related to NSTARs abandonment of its investment in RCN Corporation
fully offset by the recognition of related tax benefits of $4.5 million.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(b) | The sum of the quarters may not equal basic annual earnings per share.
|--- | ----------------------------------------------------------------------



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|Item 7. | Managements Discussion and Analysis of Financial Condition and Results of Operations (MD&A)
|------- | --------------------------------------------------------------------------------------------



Overview



NSTAR (or the Company) is a holding company engaged through its subsidiaries in the energy delivery business serving approximately 1.4
million customers in Massachusetts, including approximately 1.1 million electric distribution customers in 81 communities and approximately 300,000 natural gas distribution customers in 51 communities. NSTAR was created in 1999 in connection with
the merger of BEC Energy and Commonwealth Energy System. 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 collectively operate as NSTAR Electric. Reference in this report to NSTAR shall mean
the registrant NSTAR or NSTAR and its subsidiaries as the context requires. Reference in this report to NSTAR Electric shall mean Boston Edison, ComElectric and Cambridge Electric together. NSTARs non-utility, unregulated
operations include district energy operations (Advanced Energy Systems, Inc. and NSTAR Steam Corporation), telecommunications operations (NSTAR Communications, Inc. (NSTAR Com)) and a liquefied natural gas service company (Hopkinton LNG Corp.).
Utility operations accounted for approximately 96% of consolidated operating revenues in 2004, 2003 and 2002.



NSTAR generates its revenues primarily from the sale of energy, distribution and transmission services to customers and from its unregulated businesses. NSTARs earnings are impacted by fluctuations in unit sales
of kWh and MMbtu, which directly determine the level of distribution and transmission revenues recognized. In accordance with the regulatory rate structure in which NSTAR operates, its recovery of energy costs are fully reconciled with the level of
energy revenues currently recorded and, therefore, do not have an impact on earnings. As a result of this rate structure, any variability in the cost of energy supply purchased will impact purchased power and cost of gas sold expense and
corresponding revenues but will not affect the Companys earnings.



Cautionary Statement



The MD&A, as well as other portions
of this report, contain statements that are considered forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements may also be contained in other filings with
the Securities and Exchange Commission (SEC), in press releases and oral statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as anticipate,
estimate, expect, project, intend, plan, believe and other words and terms of similar meaning in connection with any discussion of future operating or financial performance.
These statements are based on the current expectations, estimates or projections of management and are not guarantees of future performance. Some or all of these forward-looking statements may not turn out to be what NSTAR expected. Actual results
could 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.



Examples of some important factors that could cause our actual results or outcomes to differ materially from those discussed in the
forward-looking statements include, but are not limited to, the following:



| |  |  | impact of continued cost control procedures on operating results
| | - |  | ----------------------------------------------------------------



| |  |  | weather conditions that directly influence the demand for electricity and natural gas
| | - |  | -------------------------------------------------------------------------------------



| |  |  | changes in tax laws, regulations and rates
| | - |  | ------------------------------------------



| |  |  | financial market conditions including, but not limited to, changes in interest rates and the availability and cost of capital
| | - |  | -----------------------------------------------------------------------------------------------------------------------------



| |  |  | prices and availability of operating supplies
| | - |  | ---------------------------------------------



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| |  |  | prevailing governmental policies and regulatory actions (including those of the Massachusetts Department of Telecommunications and Energy (MDTE) and Federal Energy Regulatory
Commission (FERC) with respect to allowed rates of return, rate structure, continued recovery of regulatory assets, financings, purchased power, 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
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | changes in financial accounting and reporting standards
| | - |  | -------------------------------------------------------



| |  |  | new governmental regulations or changes to existing regulations that impose additional operating requirements or liabilities
| | - |  | ----------------------------------------------------------------------------------------------------------------------------



| |  |  | changes in specific hazardous waste site conditions and the specific cleanup technology
| | - |  | ---------------------------------------------------------------------------------------



| |  |  | impact of uninsured losses
| | - |  | --------------------------



| |  |  | changes in available information and circumstances regarding legal issues and the resulting impact on our estimated litigation costs
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------



| |  |  | future economic conditions in the regional and national markets
| | - |  | ---------------------------------------------------------------



| |  |  | ability to maintain current credit ratings, and
| | - |  | -----------------------------------------------



| |  |  | the impact of terrorist acts
| | - |  | ----------------------------



Any forward-looking statement speaks only as of the date of this filing and NSTAR undertakes no obligation to publicly update forward-looking statements, whether as a result of new information, future events, or
otherwise. You are advised, however, to consult all further disclosures NSTAR makes in its filings to the SEC. Other factors in addition to those listed here could also adversely affect NSTAR. This report also describes material contingencies and
critical accounting policies and estimates in this section and in the accompanying Notes to Consolidated Financial Statements and NSTAR encourages a review of these Notes.



Critical Accounting Policies and Estimates



NSTARs discussion and analysis of its financial condition, results of operations and cash flows are based upon the accompanying Consolidated Financial
Statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of these Consolidated Financial Statements required management to make estimates and judgements
that affect the reported amount of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements. Actual results may differ from these estimates under
different assumptions or conditions.



Critical accounting policies and
estimates are defined as those that require significant judgment and uncertainties, and potentially may result in materially different outcomes under different assumptions and conditions. NSTAR believes that its accounting policies and estimates
that are most critical to the reported results of operations, cash flows and financial position are described below.



a. Revenue Recognition



Utility revenues are based on authorized rates approved by the MDTE and FERC. Revenues related to the sale, transmission and distribution of energy are generally recorded when service is rendered or energy is
delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters that are read on a systematic basis throughout the month. Meters that are not read during a given month are
estimated and trued-up in a future period. At the end of each month, amounts of energy delivered to customers since the date of the last billing date are estimated and the corresponding unbilled revenue is estimated. This unbilled electric revenue
is estimated each month based on daily generation volumes (territory



15



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##### Table of Contents

load), estimated line losses and applicable customer rates. Unbilled natural gas revenues are estimated based on estimated purchased gas volumes, estimated
gas losses and tariffed rates in effect. Accrued unbilled revenues recorded in the accompanying Consolidated Balance Sheets as of December 31, 2004 and 2003 were $54 million and $46 million, respectively.



NSTARs non-utility revenues are recognized when services are rendered or when the
energy is delivered. Revenues are based, for the most part, on long-term contractual rates.



The level of unbilled revenues is subject to seasonal weather conditions. Electric sales volumes are typically higher in the winter and summer than in the spring or fall. Gas sales volumes are impacted by colder
weather since a substantial portion of NSTARs customer base uses natural gas for heating purposes. As a result, NSTAR records a higher level of unbilled revenue during the seasonal periods mentioned above.



b. Regulatory Accounting



NSTAR follows accounting policies prescribed by GAAP, the FERC and the MDTE. As a
rate-regulated company, NSTARs utility subsidiaries are subject to the Financial Accounting Standards Board, Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS
71). The application of SFAS 71 results in differences in the timing of recognition of certain revenues and expenses from those of other businesses and industries. NSTARs energy delivery businesses remain subject to rate-regulation and
continue to meet the criteria for application of SFAS 71. This ratemaking process results in the recording of regulatory assets based on the probability of current and future cash inflows. Regulatory assets represent incurred or accrued costs that
have been deferred because they are probable of future recovery from customers. As of December 31, 2004 and 2003, NSTAR has recorded regulatory assets of $2.2 billion and $1.9 billion, respectively. NSTAR continuously reviews these assets to assess
their ultimate recoverability within the approved regulatory guidelines. NSTAR expects to fully recover these regulatory assets in its rates. If future recovery of costs ceases to be probable, NSTAR would be required to charge these assets to
current earnings. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.



c. Derivative Instruments - Power Contracts



The electric distribution industry may contract to buy and sell electricity under option contracts, which allow the distribution company the flexibility to determine when
and in what quantity to take electricity in order to align with its demand for electricity. These contracts would normally meet the definition of a derivative instrument requiring mark-to-market accounting. However, because electricity cannot be
stored and utilities are obligated to maintain sufficient capacity to meet the electricity needs of its customer base, an option contract for the purchase of electricity typically qualifies for the normal purchases and sales exception as described
in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and Derivative Implementation Group (DIG) interpretations and, therefore, does not require mark-to-market accounting.



NSTAR Electric has long-term purchase power agreements that are used primarily to meet its
standard offer obligation. The majority of these agreements are not reflected as an asset or liability on the accompanying Consolidated Balance Sheets as they qualify for the normal purchases and sales exception. However, based on DIG
interpretations, NSTAR, as of December 31, 2004, recorded four contracts at fair value on its accompanying Consolidated Balance Sheets. At December 31, 2003, NSTAR recorded six purchase power contracts at fair value. In anticipation of the end of
standard offer service in February 2005, two of the six contracts were divested in 2004 through regulatory-approved agreements. Refer to the Consolidated Financial Statements, Note O, for more detail on the buy-out of certain purchase power
contracts. As a result, the recognition of a liability for the fair value of the above-market portion of the four contracts at December 31, 2004 and for the fair value of the above-market portion of the six contracts at December 31, 2003 is
approximately $472 million and $666 million, respectively, and are reflected as a component of Deferred credits - Power contracts on the accompanying Consolidated Balance Sheets.



16



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##### Table of Contents

During the first quarter of 2005, NSTAR expects to close on a securitization financing that will affect these four
contracts that are classified as derivative instruments. NSTAR Electric has entered into buy-out agreements for all four contracts and expects to finance the buy-out payments through a securitization financing. When this occurs, the fair value of
these four contracts will be removed as a derivative instrument from the balance sheet and the securitization debt obligation will be recorded along with an offsetting regulatory asset.



At December 31, 2004, the four contracts were valued using a discounted cash flow model and a 7.5% discount rate. The market value
assumption used was provided by a third party who determines such pricing for the New England power market. Had management used an alternative assumption, the values of the contracts at December 31, 2004 and 2003 would have changed significantly. A
one percent increase or decrease to the discount rate would change the above market value for the four contracts by approximately $19 million from what is presently recorded at December 31, 2004.



NSTAR Electric recovers all of its electricity supply costs, including the above-market costs
from customers. For the four purchase power agreements at December 31, 2004, the recovery of its above-market costs occurs through 2013 for Boston Edison and through 2017 for ComElectric. These recovery periods coincide with the contractual terms of
these purchase power agreements. Therefore, in addition to the liability recorded, NSTAR also recorded a corresponding regulatory asset representing the future recovery of these actual costs. As a result, any changes to the fair value of these
contracts will not have an effect on NSTARs earnings.



d. Pension and
Other Postretirement Benefits



NSTARs annual pension and other
postretirement benefits costs are dependent upon several factors and assumptions, such as employee demographics, plan design, the level of cash contributions made to the plans, expected and actual earnings on the plans assets, the discount
rate, the expected long-term rate of return on the plans assets and health care cost trends.



In accordance with SFAS No. 87, Employers Accounting for Pensions (SFAS 87) and SFAS No. 106, Employers Accounting for Postretirement Benefits Other than Pensions (SFAS 106),
changes in pension and postretirement benefit obligations other than pensions (PBOP) associated with these factors are not immediately recognized as pension and PBOP costs in the statements of income, but generally are recognized in future years
over the remaining average service period of the plans participants.



There were no significant changes to NSTARs pension benefits in 2004, 2003 and 2002 that had a significant impact on recorded pension costs. As further described in Note H to the accompanying Consolidated Financial Statements,
NSTAR revised the discount rate at December 31, 2004 to 5.75% from 6.25% at December 31, 2003 to reflect market conditions and the characteristics of NSTARs pension obligation. The expected long-term rate of return on its pension plan assets
for 2004 remained at 8.4% (net of plan expenses), the same as 2003. These assumptions will have a significant impact on reported pension costs in future years in accordance with the cost recognition approach of SFAS 87 described above. This impact,
however, will be mitigated through NSTARs regulatory accounting treatment of qualified pension and PBOP costs. (See further discussion of regulatory accounting treatment below). In determining pension obligation and cost amounts, these
assumptions may change from period to period, and such changes could result in material changes to recorded pension and PBOP costs and funding requirements.



NSTARs Pension Plan (the Plan) assets, which partially consist of equity investments, were affected by significant declines in the financial markets from 2000
through 2002 and improvements in the financial markets for both 2003 and 2004. Fluctuations in market returns impacted the funded status of the Plan at both December 31, 2004 and 2003, and will affect pension costs in future periods.



The following chart reflects the projected benefit obligation and cost sensitivities
associated with a change in certain actuarial assumptions by the indicated percentage. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption.



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|                                                             |  |                      |  |                                      |         |   |                                        |   |        |  
|------------------------------------------------------------ |  | -------------------- |  | ------------------------------------ | ------- | - | -------------------------------------- | - | ------ | -
|(in thousands)  Actuarial Assumption                         |  | Change in Assumption |  | Impact onProjected BenefitObligation |         |   | Impact on 2004 CostIncrease/(Decrease) |  
|Pension:                                                     |  |                      |  |                                      |         |   |                                        |   |        |  
|Increase in discount rate                                    |  | 50 basis points      |  | $                                    | (58,418 | ) |                                        | $ | (4,112 | )
|Decrease in discount rate                                    |  | 50 basis points      |  | $                                    | 64,463  |   |                                        | $ | 4,442  |  
|Increase in expected long-term rate of return on plan assets |  | 50 basis points      |  |                                      | N/A     |   |                                        | $ | (4,141 | )
|Decrease in expected long-term rate of return on plan assets |  | 50 basis points      |  |                                      | N/A     |   |                                        | $ | 4,140  |  
|                                                             |  |                      | 
|Other Postretirement Benefits:                               |  |                      |  |                                      |         |   |                                        |   |        |  
|Increase in discount rate                                    |  | 50 basis points      |  | $                                    | (40,300 | ) |                                        | $ | (3,338 | )
|Decrease in discount rate                                    |  | 50 basis points      |  | $                                    | 45,080  |   |                                        | $ | 3,671  |  
|Increase in expected long-term rate of return on plan assets |  | 50 basis points      |  |                                      | N/A     |   |                                        | $ | (1,367 | )
|Decrease in expected long-term rate of return on plan assets |  | 50 basis points      |  |                                      | N/A     |   |                                        | $ | 1,367  |  
|N/A - not applicable                                         |  |                      |  |                                      |         |   |                                        |   |        |  



The Plans discount rates are
based on rates of high quality corporate bonds of appropriate maturities as published by nationally recognized rating agencies consistent with the duration of the Companys plans and through periodic bond portfolio matching. Both of these
factors contribute to managements decision for selecting the discount rate.



In determining the expected long-term rate of return on plan assets, NSTAR considers past performance and economic forecasts for the types of investments held by the Plan as well as the target allocation for the investments over a 20-year
time period. In 2004, NSTAR kept the expected long-term rate of return on plan assets at 8.4% as a result of the prevailing outlook for equity market returns. This rate is presented net of both administrative expenses and investment expenses, which
have averaged approximately 0.6% for both 2004 and 2003.



At December 31, 2003,
the Plans accumulated benefit obligation (ABO) exceeded Plan assets. The ABO represents the present value of benefits earned without considering future salary increases. Since the fair value of its Plan assets was less than the ABO, NSTAR was
required to record this difference as an additional minimum pension liability on the accompanying Consolidated Balance Sheets as of December 31, 2003.



In 2004, due to positive Plan investment performance and Company contributions over the last two years of $120 million, the fair value of the Plans assets exceeded
the Plans ABO at December 31, 2004. As a result, the minimum liability has been reversed and the prepaid pension amount has been restored to the accompanying Consolidated Balance Sheet at December 31, 2004.



On October 31, 2003, the MDTE approved NSTARs request for a reconciliation rate
adjustment mechanism related to pension and PBOP costs. As part of this ruling, NSTAR is allowed to record a regulatory asset in lieu of taking a charge to Other Comprehensive Income for the required additional minimum liability adjustment. As of
December 31, 2003, NSTAR recorded a regulatory asset of $299 million. At December 31, 2004, the regulatory asset was reversed and the prepaid pension asset of $298 million was reinstated in the accompanying Consolidated Balance Sheets.



The Plan currently meets the minimum funding requirements of the Employee Retirement
Income Security Act of 1974. While not required to make contributions to the Plan, NSTAR anticipates that it will contribute approximately $35 million to the Plan in 2005. NSTAR believes it has adequate access to capital resources to support these
contributions.



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e. Decommissioning Cost Estimates



The accounting for decommissioning costs of nuclear power plants involves significant estimates related to costs to be incurred many years
in the future. Changes in these estimates will not affect NSTARs results of operations or cash flows because these costs will be collected from customers through NSTARs transition charge filings with the MDTE.



While NSTAR no longer directly owns any operating nuclear power plants, NSTAR Electric
collectively owns, through its equity investments, 14% of Connecticut Yankee Atomic Power Company, 14% of Yankee Atomic Electric Company, and 4% of Maine Yankee Atomic Power Company, (collectively, the Yankee Companies). Periodically,
NSTAR obtains estimates from the management of the Yankee Companies on the cost of decommissioning the Connecticut Yankee nuclear unit (CY), the Yankee Atomic nuclear unit (YA), and the Maine Yankee nuclear unit (MY). These nuclear units are
completely shut down and are currently conducting decommissioning activities.



Based on estimates from the Yankee Companies management as of December 31, 2004, the total remaining cost for decommissioning each nuclear unit is approximately as follows: $630 million for CY, $119 million for YA and $292 million for
MY. Of these amounts, NSTAR Electric is obligated to pay $88.2 million towards the decommissioning of CY, $16.7 million toward YA, and $11.7 million toward MY. These amounts are recorded in the accompanying Consolidated Balance Sheets as Power
contract liabilities with a corresponding regulatory asset and do not impact the current results of operations and cash flow. These estimates may be revised from time to time based on information available to the Yankee Companies regarding future
costs.



The Yankee Companies have received approval from FERC for recovery of
these costs and NSTAR expects any additional increases to these costs to be included in future rate applications with the FERC, with any resulting adjustments being charged to their respective sponsors, including NSTAR Electric. NSTAR Electric would
recover its share of any allowed increases from customers through the transition charge.



CYs estimated decommissioning costs increased significantly in 2003 and the increase reflects the fact that CY is now self-performing all work to complete the decommissioning of the plant due to the termination
of the decommissioning contract with Bechtel Power Corporation (Bechtel). In July 2004, CY filed with FERC for recovery of these increased costs. In August 2004, FERC issued an order accepting the new rates, beginning in February 2005, subject to
refund.



CY is currently in litigation with Bechtel over the termination of its
decommissioning contract. Additionally, Bechtel filed a complaint against CY asserting several claims as well as wrongful termination. Bechtel sought to garnish the decommissioning trust and related payments. In October 2004, Bechtel and CY entered
into a stipulation under which Bechtel relinquished its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CYs real property in Connecticut with a book value of $7.9 million
and the escrowing of portions of the sponsors periodic payments, up to a total of $41.7 million, all of which the sponsors, which include NSTAR Electric, are scheduled to pay to CY through June 30, 2007. This stipulation is subject to approval
of the Court and would not be implemented until the Court found that such assets were subject to attachment. CY intends to contest the ability of Bechtel to attach these assets. Discovery is underway and a trial has been scheduled for May 2006.
NSTAR cannot predict the timing or outcome of the litigation with Bechtel but does not expect a material impact on NSTARs financial position, results of operation or cash flows.



Asset Retirement Obligations



On January 1, 2003, NSTAR adopted SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS 143). SFAS 143 establishes accounting and reporting
standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition,
construction, development and/or the normal



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operation of a long-lived asset, except for certain obligations under lease arrangements. SFAS 143 requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is
accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss
upon settlement.



NSTAR has identified certain immaterial long-lived assets,
including obligations under lease and easement arrangements, and has determined that it is legally responsible to remove such property.



For its regulated utility businesses, NSTAR has identified legal retirement obligations that are currently not material to its financial statements. The recognition of a
potential asset retirement obligation will have no impact on its earnings. In accordance with SFAS 71, for NSTARs rate-regulated utilities, NSTAR would establish regulatory assets or liabilities to defer any differences between the liabilities
established for ratemaking purposes and those recorded as required under SFAS 143.



For NSTARs regulated utility businesses, the ultimate cost to remove utility plant from service (cost of removal) is recognized as a component of depreciation expense in accordance with approved regulatory treatment. As of December
31, 2004 and 2003, the estimated amount of the cost of removal included in regulatory liabilities was approximately $259 million and $223 million, respectively, based on the estimated cost of removal component in current depreciation rates.



NSTAR has also identified several long-lived assets, in which it has legal
obligations to remove such property, for its non-regulated businesses. As a result, in 2003, NSTAR recorded an increase in non-utility property of approximately $0.6 million, an asset retirement liability of approximately $1 million and a cumulative
effect of adoption after tax, reducing net income by $0.4 million in 2003. The cumulative effect adjustment was recorded as part of 2003 Depreciation and amortization expense on the accompanying Consolidated Statements of Income.



During 2004, the FASB issued an exposure draft, Accounting for Conditional Asset
Retirement Obligations, an interpretation of FASB Statement No. 143. The interpretation clarifies when an entity would be required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future
event if the liabilitys fair value can be reasonably estimated. Uncertainty surrounding the timing and method of settlement that may be conditional on events occurring in the future would be factored into the measurement of the liability
rather than the recognition of the liability. The interpretation would be effective for NSTAR no later than the end of fiscal year 2005. NSTAR is currently assessing the impact that the interpretation will have on its consolidated financial
position, results of operations and cash flows.



Variable Interest Entities



In 2004, the FASB issued an exposure draft, Consolidation of
Variable Interest Entities, as revised in December 2003 (FIN 46R), which addresses the consolidation of variable interest entities (VIE) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have
sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE
is the enterprise with the majority of the risks or rewards associated with the VIE. This interpretation had two effective dates: December 31, 2003 and March 31, 2004.



NSTAR has a wholly owned special purpose subsidiary, BEC Funding LLC, established to undertake the sale of $725 million in notes to a
special purpose trust created by two Massachusetts state agencies. NSTAR consolidates this entity. As part of NSTARs assessment of FIN 46R and, for compliance at December 31, 2003, NSTAR reviewed the substance of this entity to determine if it
is still proper to consolidate this entity. Based on its review, NSTAR has concluded that BEC Funding LLC is a VIE and should continue to be consolidated by NSTAR.



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For the March 31, 2004 effective date of FIN 46R, NSTAR evaluated other entities with which it conducts significant
transactions, including companies that supply power to NSTAR through its purchase power agreements. NSTAR determined that it is possible that five of these companies may be considered VIEs. These companies have power plants that have daily capacity
output ranging from 20 megawatts (MW) to 330 MW. Through December 31, 2004 and 2003, NSTAR purchased a total of approximately 4,001 megawatt-hours (MWH) and 4,487 MWH, respectively, under these agreements. These purchases approximate 17% of the
total MWH purchased by NSTAR for years ended December 31, 2004 and 2003 and amounted to approximately $381 million and $386 million, respectively. In order to determine if these counterparties are VIEs and if NSTAR is the primary beneficiary of
these counterparties, NSTAR concluded that it needed more information from the entities. NSTAR attempted to obtain the information required and requested, in writing, these entities provide the Company with the necessary information. However, each
of the entities has indicated that they will not provide the requested information as they are not contractually obligated to provide such confidential information. Since NSTAR was unable to obtain the necessary information and, as allowed under a
scope exception in FIN 46R, the accompanying Consolidated Financial Statements do not reflect the consolidation of any entities with which NSTAR has a purchase power agreement.



Additionally, during 2004, NSTAR executed purchase power buy-out/restructuring agreements with a majority of the entities from which NSTAR
attempted to obtain additional information in order to determine if these entities are VIEs. These buy-out/restructuring agreements received regulatory approval in January 2005. Refer to Consolidated Financial Statements, Note O, for more
detail on the purchase power buy-out agreements. As a result, NSTAR will no longer pursue obtaining the necessary information to determine whether it has a potential variable interest in these entities.



New Accounting Standards



In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment. This
Standard addresses the accounting for transactions in which a company receives employee services in exchange for (a) equity instruments of the company or (b) liabilities that are based on the fair value of the companys equity instruments or
that may be settled by the issuance of such equity instruments. This Standard also eliminates the ability to account for share-based compensation transactions using Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to
Employees, and requires that such transactions be accounted for using a fair-value-based method. The Standard is effective for periods beginning after June 15, 2005. NSTAR is currently assessing its valuation options allowed in this Standard
but, preliminarily, expects this Standard to impact annual earnings by approximately $1.5 million pre-tax, or $0.02 per share.



Generating Assets Divestiture



Blackstone Station



On April 8, 2003, Cambridge Electric completed the sale of Blackstone Station to Harvard University (Harvard) for $14.6 million; the net proceeds ($10.4 million) from the
sale were used to reduce Cambridge Electrics transition charge. The sale was approved by the MDTE on March 14, 2003. Also on April 8, 2003, NSTAR Steam Corporation completed the sale of its Blackstone Station steam assets to Harvard for $3
million. The net impact of these transactions resulted in a pretax gain of $1.3 million. Under terms of an operating agreement, NSTAR Steam continued to manage the day-to-day operations of the steam plant on this site until April 8, 2004.



Rate and Regulatory Proceedings



a. Service Quality Indicators



Service quality indicators are established performance benchmarks for certain identified
measures of service quality relating to customer service and billing performance, customer satisfaction, and reliability and safety performance for all Massachusetts utilities. NSTAR Electric and NSTAR Gas are required to report annually to the MDTE
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.



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On March 1, 2004, NSTAR Electric and NSTAR Gas filed their 2003 Service Quality Reports with the MDTE that demonstrated
the Companies achieved levels of reliability and performance; the reports indicate that no penalty was assessable for 2003. The MDTE concurred with NSTARs determination in an order issued in October 2004. NSTAR monitors its service
quality continuously to determine its contingent liability, and if its probable that a liability has been incurred and is estimable, a liability would be accrued. Annually, each NSTAR utility subsidiary makes a service quality performance
filing with the MDTE. Any settlement or rate order that would result in a different liability level from what has been accrued would be adjusted in the period that the MDTE issues an order determining the amount of any such liability. Recently, the
MDTE voted to initiate an investigation into potentially modifying the service quality indicators for all Massachusetts utilities. Until any such order is issued, the current service quality indicators will remain in place. NSTAR currently cannot
predict the outcome of this investigation or its impact.



As of December 31,
2004, NSTAR Electrics and NSTAR Gas 2004 performance has exceeded the applicable established benchmarks and, as such, that no liability has been accrued for 2004.



b. Retail Electric Rates



Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through either standard offer or default service for those
who choose not to buy energy from a competitive energy supplier. Standard offer service will end on February 28, 2005. Therefore, effective March 1, 2005, all customers who have not chosen to receive service from a competitive supplier will be
provided default service. Default service rates are reset every six months (every three months for large commercial and industrial customers). The price of default service is intended to reflect the average competitive market price for power. As of
December 31, 2004, 2003 and 2002, customers of NSTAR Electric had approximately 24%, 26% and 27%, respectively, of their load requirements provided by competitive suppliers.



On December 21, 2004, the FERC issued an order approving Boston Edisons October 2004 request to modify its Open Access Transmission
Tariff (OATT). Effective January 1, 2005, Boston Edison is allowed to include 50 percent of construction work in progress in its rate base for transmission projects by including this amount in its local network service transmission rate formula,
rather than capitalizing Allowance for Funds Used During Construction (AFUDC) charges on the entire construction expense balance. The order is subject to Boston Edison filing annual reports of its long-term transmission plan.



In December 2004, NSTAR Electric filed proposed transition rate adjustments for 2005,
including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2004. The MDTE subsequently approved tariffs for each retail electric subsidiary effective January 1, 2005. The filings
are to be updated in February 2005 to reflect final 2004 costs and revenues which are subject to final reconciliation.



On February 1, 2005, the Independent System Operator  New England began operating as a Regional Transmission Organization. As a result, NSTAR has given notice to
the RTO and other interested parties of its intent to file for proposed changes to its OATT. This change is expected to provide for consistent application of the OATT among all NSTAR Electric companies. The 2004 OATT and the related revenue have
been based on this proposed change. If successful, NSTAR Electric expects to include the impact in its 2005 billing rates.



Effective January 1, 2005, NSTAR Electrics Standard Offer Service Fuel Adjustment (SOSFA) rates for each of Boston Edison, ComElectric and Cambridge were modified
to a level of 1.564 cents per kilowatt-hour with the approval of the MDTE.



Effective October 1, 2004, Boston Edisons SOSFA rate was modified to 1.223 cents per kilowatt-hour from zero upon approval by the MDTE. The MDTE has allowed companies to adjust prices to reduce deferred cost balances that arise due to
rapidly changing market costs for the oil and natural gas used to generate electricity and the SOSFA is designed to collect the costs of fuel that companies incur for purchasing electricity from their suppliers to serve their standard offer service
customers. Effective September 1, 2003, the Boston Edison SOSFA



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was reduced to zero while the ComElectric and Cambridge Electric SOSFAs were increased to 1.424 cents per kilowatt-hour until January 1, 2004 when they were
reduced to 1.223 cents per kilowatt-hour. These changes followed an increase in this rate adjustment from zero to 0.902 cents per kilowatt-hour that was effective May 1, 2003 for all three NSTAR Electric companies. The SOSFA was at zero from April
1, 2002 through April 30, 2003 for all three NSTAR Electric companies. The MDTE has ruled that these fuel index adjustments are excluded from the 15% rate reduction requirement under the 1997 Massachusetts Electric Restructuring Act.



In December 2003, NSTAR Electric filed proposed transition rate adjustments for 2004,
including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2003. The MDTE subsequently approved tariffs for each retail electric subsidiary effective January 1, 2004. The filings
were updated in February 2004 to include final costs and revenues for 2003.



On
December 1, 2003, NSTAR Electric and NSTAR Gas filed their annual reconciliation report on their pension and PBOP rate adjustment mechanism. Hearings were held during 2004. NSTAR anticipates an order by the end of the first quarter of 2005. NSTAR
cannot predict the overall timing and result of this order on its financial position or results of operations.



c. Wholesale Market Rule Changes



Standard Market Design (SMD)



Pursuant to
orders issued by the FERC, wholesale electric markets in New England have been operating under SMD since March 1, 2003. Under SMD, generators are dispatched on a least cost basis until the generation dispatched equals the amount of energy required.
The clearing price is set at the price of the next available megawatt of generation and is paid to all dispatched generators. SMD provides an additional market in which wholesale power costs can be hedged a day in advance through binding financial
commitments. Also, under SMD, wholesale power clearing prices vary by location, called load zones, with prices in load zones with less efficient generation being higher than in load zones with more efficient generation during periods when
transmission constraints prevent the lower cost generation from moving from one load zone to another. This mechanism is known as Locational Marginal Pricing (LMP). NSTAR Electrics service territory covers two of the eight load zones in New
England: Northeastern MA (NEMA) and Southeastern MA (SEMA). NEMA is import-constrained and SEMA is export-constrained. The majority of NSTARs customers are in the NEMA load zone. During periods of transmission constraints, NEMA has a higher
LMP than SEMA. As part of SMD, load-serving entities, like NSTAR Electric, were granted proceeds from the auction of financial transmission rights that is conducted by ISO-NE. NSTAR Electric uses proceeds to mitigate costs to customers.



Locational Installed Capacity (LICAP)



The ISO-NE has proposed a new market rule designed to compensate wholesale generators for
their capacity, called LICAP. The proposed LICAP rules require electric load serving entities (LSE), like NSTAR Electric, to procure capacity within the zones where load is served. The current market structure allows capacity, located anywhere in
New England, to count towards a LSEs obligation, regardless of load zone. At this point, it appears likely that NSTARs new 345kV transmission project will reduce transmission constraints causing capacity prices between NEMA and SEMA to
converge, which could ultimately render this locational aspect of LICAP a non-factor for NSTAR customers. However, since proposed market rules require that a certain amount of capacity be procured in the NEMA zone and, depending on how many market
rules are finally adopted, these requirements could impact pricing for capacity in the NEMA zone. Additionally, much of the capacity in the NEMA zone has issued notice of its intent to file with the FERC for cost of service type agreements called
Reliability Must Run agreements for the recovery of their costs prior to the implementation of LICAP. The proposed LICAP rules will impact overall capacity pricing levels in New England. Since the New England market as a whole is currently in a
surplus position, capacity trades at a relatively low price. One of the goals of LICAP is to provide a higher level of compensation to generators than what is currently being earned in this surplus market. This will likely increase the price of
power to NSTARs customers. The proposed LICAP market



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rules are contentious and are currently being litigated at FERC and in the courts. A final FERC ruling on the issue is expected in 2005 and the current
schedule calls for an implementation date of January 1, 2006. Until these rules are finalized and approved, NSTAR cannot predict the actual impact these changes will have on NSTAR Electric and its customers.



Regional Transmission Organization (RTO)



On March 24, 2004, the FERC decided to schedule hearings for a joint return on equity (ROE)
filing made by participating New England Transmission Owners, including NSTAR Electric. The filing requested an increase in the base ROE component of the regional and local transmission rates, to be provided under the Regional Transmission
Organization for New England (RTO-NE) open access transmission tariff (OATT), to a single ROE of 12.8% for all regional and local transmission rates. Presently, transmission service in New England is provided under a two-tier structure, with the
potential for the ROE for local service to be different than for regional service for the same transmission provider. FERC has previously approved other RTO filings for an ROE adder of 50 basis points in regional rates as an incentive for joining an
RTO for regional service. In addition, FERC also scheduled hearings to address the proposal for an additional 100 basis points in regional rates to provide an incentive to build new transmission facilities. The Transmission Owners maintain that
sufficient equity returns are needed to elicit the necessary investments in transmission within an RTO. Settlement negotiations occurred in April 2004 before a FERC administrative law judge and were unsuccessful. Hearings on the base ROE and 100
basis point adder began in January 2005.



The joint ROE filing among the
Transmission Owners was made in connection with the proposed formation of RTO-NE by the Transmission Owners and ISO-NE, the present administrator of the New England Power Pool (NEPOOL) OATT, and is an important and integral component of the
agreement to form an RTO for the New England region. On November 3, 2004, the FERC accepted a settlement agreement among NEPOOL, ISO-NE and the New England Transmission Owners, including NSTAR Electric, which resolved many issues left outstanding
from FERCs March 2004 Order conditionally approving the formation of RTO-NE. The November 3rdOrder also
provided clarification of certain aspects of the March 2004 Order regarding the Transmission Owners request for an increase in the base return on equity component of the regional and local transmission rates. This clarification narrowed the
scope of issues to be addressed during the January 2005 hearings on the base ROE proposal and the Transmission Owners proposal for an additional 100 basis points in regional rates to provide an incentive to build new transmission facilities.
Finally, the November 3rdOrder required the satisfaction of several ministerial conditions before ISO-NE could
begin to operate as an RTO. ISO-NE and the Transmission Owners have since satisfied such conditions and provided 30 days notice to FERC and NEPOOL that on February 1, 2005, ISO-NE would begin to operate as an RTO. Effective February 1, 2005, the
ISO-NE is an independent entity, without a financial interest in the regions marketplace, having operating authority over the New England transmission grid and the responsibility to make impartial decisions on the development and
implementation of market rules. The ISO-NE operates under a series of contractual arrangements that define its functions and responsibilities, including a Transmission Operating Agreement, which governs the relationship between the owners of
transmission facilities, such as NSTAR Electric, and the ISO-NE, as the operator of the New England transmission grid. Separate agreements govern the operation of the spot power and related markets, the ISO-NEs interactions with market
participants and merchant transmission facilities. NSTARs management cannot estimate the impact of the RTO on the Company.



d. Natural Gas Rates



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



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In addition to delivery service rates, NSTAR Gas tariffs include a seasonal Cost of Gas Adjustment Clause (CGAC)
and a Local Distribution Adjustment Clause (LDAC). The CGAC provides for the recovery of all gas supply costs from firm sales customers or default service customers. The LDAC provides for the recovery of certain costs applicable to both sales and
transportation customers. The CGAC is filed semi-annually for approval by the MDTE. The LDAC is filed annually for approval. In addition, NSTAR Gas is required to file interim changes to its CGAC factor when the actual costs of gas supply vary from
projections by more than 5%.



Due to the increase in wholesale natural gas
prices, NSTAR Gas was allowed by the MDTE to increase its winter seasonal CGAC factor effective November 1, 2002 by 16.7% over the prior winter seasons factor. The CGAC factor was allowed to increase two additional times during that winter
season due to the increases in the wholesale cost of gas. On November 1, 2003, the winter season CGAC factor was set at a level 10% higher than the average for the prior winter season due to higher wholesale gas costs. On January 1, 2004, the CGAC
factor was allowed to increase by 9.9% to reflect an additional increase in the cost of gas.



In the last three years, the winter season CGAC factor was revised upward to reflect increases in the cost of gas caused by varying market conditions. To date, the CGAC factor for the winter of 2003-2004 has ranged
from $0.8121 per therm to $0.8925; in the winter of 2002-2003, the CGAC ranged from $0.6139 per therm to $0.8936 per therm; the range for the winter of 2001-2002 was $0.5261 per them to $0.6139 per therm.



Other Legal Matters



In the normal course of its business, NSTAR and its subsidiaries are involved in certain legal matters, including civil litigation.
Management is unable to fully determine a range of reasonably possible court-ordered damages, settlement amounts, and related litigation costs (legal liabilities) that would be in excess of amounts accrued and amounts covered by
insurance. Based on the information currently available, NSTAR does not believe that it is probable that any such legal liabilities will have a material impact on its consolidated financial position. However, it is reasonably possible that
additional legal liabilities that may result from changes in circumstances could have a material impact on its results of operations for a reporting period.



RCN Abandonment



On December 24, 2003, NSTAR exited its investment in RCN and formally abandoned its 11.6 million shares of RCN common stock. As a result, NSTAR recorded a pre-tax charge of approximately $6.8 million, or $0.08 per
share. NSTAR determined that the abandonment at that time was the most tax efficient, cost effective and expedient means to exit its RCN investment. NSTAR determined other alternatives such as a sale of the shares would be less beneficial as a
result of the number of shares held by NSTAR; the trading value in shares of RCN common stock; the potential negative impact that a large volume of sales of RCN common stock could have on the value of such shares; the length of time required to exit
such investment through a sale of such shares and the fact that no block purchasers expressed an interest in purchasing such shares. NSTAR determined that the benefit of a tax realization event at that time and in that manner outweighed any benefit
that it would likely realize from any other alternative, including the future sale of such shares in an orderly fashion consistent with all laws, rules and regulations. As a result of this abandonment, the investment was written down to zero as of
December 31, 2003. The cumulative increase in fair value of these shares since December 31, 2002, including the impact of the abandonment charge for these shares, is included in Other comprehensive income, net on the accompanying Consolidated
Statements of Comprehensive Income.



Income Tax Matters



a. RCN Abandonment Tax Treatment



As a result of the RCN share abandonment, the Company claimed an ordinary loss on its 2003
tax return for this item. The ordinary loss tax treatment resulted in the Company realizing the benefits represented by the tax asset recorded on its books that resulted from the previous write-down of this asset for financial reporting purposes.



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The requirement for a tax valuation allowance, therefore, is no longer applicable. Accordingly, the Company reversed this reserve as of December 31, 2003.



The Company believes it is more likely than not that it is entitled to this
ordinary loss deduction. The Company expects the Internal Revenue Service (IRS) to review this transaction and it is possible that the IRS will disagree. In accordance with the Companys tax policy as it relates to uncertain tax positions, the
Company has established a loss contingency of approximately $44 million at December 31, 2003. This amount represents the tax impact to the Company should the ordinary loss ultimately be recharacterized to a capital loss. This contingent liability is
recorded as part of Deferred credits - Other on the accompanying Consolidated Balance Sheets.



If the Companys position is not upheld, the Company may be required to make future cash expenditures to the IRS that may impact NSTARs cash requirements in future periods.



b. Tax Valuation Allowance



SFAS 109, Accounting for Income Taxes, prohibits the recognition of all or a
portion of deferred income tax benefits if it is more likely than not that the deferred tax asset will not be realized. NSTAR had determined that it was more likely than not that a current or future income tax benefit would not be realized relating
to the write-downs of its RCN investment that were recorded in the second and fourth quarters of 2002 and previously in the first quarter of 2001. These write-downs resulted from the significant declines in the market value of the telecommunications
sector, including RCN. As a result of this uncertainty, NSTAR recorded a $77.6 million tax valuation allowance on the entire tax benefit associated with these write-downs during 2001 and 2002. During 2003 and 2002, as a result of previously
unanticipated capital gain transactions, NSTAR recognized $8.5 million and $3.9 million, respectively, of this tax benefit.



Additionally, based on the IRS review of NSTARs 1999 and 2000 federal income tax returns, NSTAR recognized the tax benefits relating to the incremental operating
losses from the joint venture that were allocated to NSTAR. These tax returns are currently at the Office of IRS Appeals on other matters. The tax valuation allowance included reserves related to the tax treatment of these losses through June 19,
2002, the final date of JV loss allocation to NSTAR. Each of the tax returns filed for 1999 through 2001 claimed operating losses. The tax return filed for 2002 claimed the remaining portion of these operating losses. Based on the IRS examining
agents review, no adjustment for the years under audit was proposed. This determination was arrived at in the fourth quarter of 2002 and, as a result, NSTAR applied the treatment of these operating losses for all years on a consistent basis,
allowing a reduction to its valuation allowance of approximately $19.7 million as a reduction to income tax expense included as a component of the write-down to the RCN investment.



On December 24, 2003, NSTAR exited from its investment in RCN and formally abandoned the 11.6 million shares of RCN common stock. As
mentioned above, a tax valuation allowance had been established in a previous year to offset the potential future tax benefits resulting from write-downs of NSTARs investment in RCN. As a result of the abandonment, the Company claimed an
ordinary loss on its 2003 tax return. This treatment results in the Company realizing the benefits represented by the tax asset recorded on its books that resulted from the previous write-downs of this investment for financial reporting purposes.
The requirement for a tax valuation allowance, therefore, is no longer applicable. As a result, the Company reduced the remaining valuation allowance to zero at December 31, 2003.



Results of Operations



The following section of MD&A compares the results of operations for each of the three fiscal years ended December 31, 2004, 2003 and 2002 and should be read in
conjunction with the accompanying Consolidated Financial Statements and the accompanying Notes to Consolidated Financial Statements included elsewhere in this report.



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2004 compared to 2003



Earnings and Operations Overview



Earnings per common share were as follows:



|        |  |                          |      |      |   |          |  |    
|------- |  | ------------------------ | ---- | ---- | - | -------- |  | ---
|        |  | Years ended December 31,
|        |  | 2004                     |      | 2003 |   | % Change
|Basic   |  | $                        | 3.55 |      | $ | 3.42     |  | 3.8
|Diluted |  | $                        | 3.51 |      | $ | 3.40     |  | 3.2



Net income was $188.5 million for 2004
compared to $181.6 million for 2003. Factors that contributed to the $6.9 million, or 3.8%, increase in 2004 earnings include higher electric distribution revenues due to higher rates, interest savings on the Companys outstanding indebtedness,
and a reduction in operations and maintenance expense. In addition, 2004 results reflect the first full year of the Companys pension and other postretirement benefit obligations other than pension (PBOP) rate mechanism. This mechanism was
implemented in September 2003 and, at that time, the Company expensed $18 million of pension and PBOP costs, which were deferred during the first eight months of 2003. See Critical Accounting Policies and Estimates, Pension and
Other Postretirement Benefits, in this MD&A for more information on the MDTE order.



NSTAR in 2004 generated $437.5 million of cash from operations sufficient to fund approximately $313.4 million of net capital expenditures, and $119.8 million of cash dividends. The Companys capital expenditures
contributed to NSTAR s solid operational performance in reliability, restoration, and customer service measurements. Favorable market conditions and the Companys strong credit ratings contributed to the Companys 2004 refinancing
activities. These financing activities included the retirement of $181 million of 7.80% series of Debentures in March 2004 and a reduction in short-term borrowings of $77.7 million from year-end 2003. This retirement was temporarily funded with
short-term borrowings, which were subsequently paid down with the proceeds from the issuance of a 10-year, $300 million 4.875% series of Debentures, which was completed in April 2004.



Energy sales and weather



The following is a summary of retail electric and firm gas energy sales for the years indicated:



|                            |  |                          |  |            |  |          |  
|--------------------------- |  | ------------------------ |  | ---------- |  | -------- | -
|                            |  | Years ended December 31, | 
|                            |  | 2004                     |  | 2003       |  | % Change |  
|Retail Electric Sales - MWH |  |                          |  |            |  |          |  
|Residential                 |  | 6,564,494                |  | 6,492,738  |  | 1.1      |  
|Commercial                  |  | 12,693,217               |  | 12,417,719 |  | 2.2      |  
|Industrial                  |  | 1,651,389                |  | 1,694,184  |  | (2.5     | )
|Other                       |  | 168,733                  |  | 170,012    |  | (0.8     | )
|                            |  |                          |  |            |  |          |  
|Total retail sales          |  | 21,077,833               |  | 20,774,653 |  | 1.5      |  
|                            |  |                          |  |            |  |          |  
|                            | 
|                            |  | Years ended December 31, | 
|                            |  | 2004                     |  | 2003       |  | % Change |  
|Firm Gas Sales - BBTU       |  |                          |  |            |  |          |  
|Residential                 |  | 23,051                   |  | 24,062     |  | (4.2     | )
|Commercial                  |  | 15,614                   |  | 16,152     |  | (3.3     | )
|Industrial and other        |  | 8,302                    |  | 8,175      |  | 1.6      |  
|                            |  |                          |  |            |  |          |  
|Total firm sales            |  | 46,967                   |  | 48,389     |  | (2.9     | )
|                            |  |                          |  |            |  |          |  



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In terms of customer sector characteristics, industrial sales are less sensitive to weather than residential and
commercial sales which are influenced by temperature extremes. Despite the overall warmer winter weather in 2004, the increase in electric sales is attributable in part to the commercial sector where building expansions created the resulting
additional energy use. Electric residential and commercial customers represented approximately 31% and 59%, respectively, of NSTARs total sales mix for 2004 and provided 39% and 54% of distribution and transmission revenues, respectively.
Refer to the Electric revenues section below for a more detailed discussion. Industrial sales are primarily influenced by national and local economic conditions and sales to these customers reflect a sluggish economic environment and
decreased manufacturing production.



Unit sales of electricity in 2005 are
expected to grow at a rate of 2% to 3%. Firm gas sales are expected to grow at a rate of 5% to 6%. However, NSTAR forecasts its electric and natural gas sales based on normal weather conditions. Actual results may differ from those projected due to
actual weather conditions above or below normal weather levels, and other factors. Refer to Cautionary Statement in this section.



|                                                |  |       |    |  |       |    |  |                     
|----------------------------------------------- |  | ----- | -- |  | ----- | -- |  | --------------------
|                                                |  | 2004  |    |  | 2003  |    |  | Normal30-YearAverage
|Heating degree-days                             |  | 5,986 |    |  | 6,263 |    |  | 6,033               
|Percentage (warmer) colder than prior year      |  | (4.4  | )% |  | 10.7  | %  |  |                     
|Percentage (warmer) colder from 30-year average |  | (0.8  | )% |  | 5.4   | %  |  |                     
|                                                |  |       |   
|Cooling degree-days                             |  | 632   |    |  | 755   |    |  | 777                 
|Percentage (cooler) than prior year             |  | (16.3 | )% |  | (22.3 | )% |  |                     
|Percentage (cooler) than 30-year average        |  | (18.7 | )% |  | (2.8  | )% |  |                     



Weather conditions impact electric
and, to a greater extent during the winter, gas sales in NSTARs service area. Despite a very cold January, the first quarter of 2004 was 5.4% warmer than the same period in 2003, followed by continued warmer temperatures for the second
quarter. The cooler than prior year third quarter resulted in reduced air conditioning demand that preceded a slightly colder fourth quarter of 2004. The comparative information above relates to heating and cooling degree-days for 2004 and 2003 and
the number of degree-days in a normal year as represented by a 30-year average. A degree-day is a unit measuring how much the outdoor mean temperature falls below (heating degree-day) or rises above (cooling degree-day) a
base of 65 degrees. Each degree below or above the base temperature is measured as one degree-day.



Operating revenues



Operating revenues
for 2004 increased 1.5% from 2003 as follows:



|                                     |  |      |         |      |   |                     |  |   |         |   |  |       |  
|------------------------------------ |  | ---- | ------- | ---- | - | ------------------- |  | - | ------- | - |  | ----- | -
|                                     |  |      |         |      |   | Increase/(Decrease) | 
|(in millions)                        |  | 2004 |         | 2003 |   | Amount              |  |   | Percent |  
|Electric revenues                    |  |      |         |      |   |                     |  |   |         |   |  |       |  
|Retail distribution and transmission |  | $    | 852.7   |      | $ | 860.7               |  | $ | (8.0    | ) |  | (0.9  | )
|Energy, transition and other         |  |      | 1,483.3 |      |   | 1,451.1             |  |   | 32.2    |   |  | 2.2   |  
|                                     |  |      |         |      |   |                     |  |   |         |   |  |       |  
|Total retail                         |  |      | 2,336.0 |      |   | 2,311.8             |  |   | 24.2    |   |  | 1.0   |  
|Wholesale                            |  |      | 16.9    |      |   | 21.5                |  |   | (4.6    | ) |  | (21.4 | )
|                                     |  |      |         |      |   |                     |  |   |         |   |  |       |  
|Total electric revenues              |  |      | 2,352.9 |      |   | 2,333.3             |  |   | 19.6    |   |  | 0.8   |  
|                                     |  |      |         |     
|Gas revenues                         |  |      |         |      |   |                     |  |   |         |   |  |       |  
|Firm and transportation              |  |      | 147.7   |      |   | 149.4               |  |   | (1.7    | ) |  | (1.1  | )
|Energy supply and other              |  |      | 344.6   |      |   | 315.8               |  |   | 28.8    |   |  | 9.1   |  
|                                     |  |      |         |      |   |                     |  |   |         |   |  |       |  
|Total gas revenues                   |  |      | 492.3   |      |   | 465.2               |  |   | 27.1    |   |  | 5.8   |  
|                                     |  |      |         |     
|Unregulated operations revenues      |  |      | 109.1   |      |   | 113.2               |  |   | (4.1    | ) |  | (3.6  | )
|                                     |  |      |         |      |   |                     |  |   |         |   |  |       |  
|Total operating revenues             |  | $    | 2,954.3 |      | $ | 2,911.7             |  | $ | 42.6    |   |  | 1.5   |  
|                                     |  |      |         |      |   |                     |  |   |         |   |  |       |  



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Electric revenues



Electric retail distribution revenues primarily represent charges to customers for the Companys recovery of its capital investment,
including a return component, and operation and maintenance related to its electric distribution infrastructure. The transmission revenue component represents charges to customers for the recovery of costs to move the electricity over high voltage
lines from the generator to the Companys substations. Despite a 1.5% increase in retail MWH sales, substantially all in the residential and commercial sectors, the decrease in retail distribution and transmission revenues is primarily due to
transmission-related true-up adjustments.



NSTARs largest earnings
sources are the revenues derived from distribution rates approved by the MDTE. The level of distribution revenues is affected by weather conditions and the economy. Weather conditions affect sales to NSTARs residential and small commercial
customers. Economic conditions affect NSTARs large commercial and industrial customers.



Energy, transition and other revenues primarily represent charges to customers for the recovery of costs incurred by the Company in order to acquire the energy supply on behalf of its customers and a transition charge
for recovery of the Companys prior investments in generating plants and the costs related to long-term power contracts. The energy revenues relate to customers being provided energy supply under either standard offer or default service. Energy
supply contract prices vary among the NSTAR Electric companies and for standard offer and default service customers. However, the retail revenues related to standard offer and default services are fully reconciled to the costs incurred and have no
impact on NSTARs consolidated net income. Furthermore, energy and transition revenues are fully reconciled with the cost currently recognized by the Company and, as a result, do not have an effect on the Companys earnings. Other revenues
primarily relate to the Companys ability to effectively reduce stranded costs (mitigation incentive), rental revenue from electric property and annual cost reconciliation true-up adjustments. In 2004, the cost reconciliation true-up
adjustments increased revenues by approximately $4.7 million. The $32.3 million increase in energy, transition and other revenues is primarily attributable to higher rates for default service and standard offer service, which include ComElectric and
Cambridge Electric standard offer service fuel index adjustments throughout 2004 and for Boston Edison in the fourth quarter of 2004.



Wholesale revenues relate to services provided to municipalities and certain other governmental authorities. This decrease in 2004 wholesale revenues reflects the
expiration of two wholesale power supply contracts in 2003 and one contract in 2004. After October 2005, NSTAR Electric anticipates it will no longer have contracts for the supply of wholesale power. Amounts collected from wholesale customers are
credited to retail customers through the transition charge. Therefore, the expiration of these contracts will have no impact on results of operations.



Gas revenues



Firm and transportation gas revenues primarily represent charges to customers for NSTAR Gas recovery of costs of its capital investment in its gas infrastructure,
including a return component, and for the recovery of costs for the ongoing operation and maintenance of that infrastructure. The transportation revenue component represents charges to customers for the recovery of costs to move the natural gas over
pipelines from gas suppliers to take stations located within NSTAR Gas service area. The $1.7 million decrease in firm and transportation revenues is attributable to warmer weather, conservation efforts, the decrease in sales volumes of 2.9%
offset by increased revenues related to carrying costs earned as part of a reconciliation rate adjustment mechanism related to pension and PBOP that was approved by the MDTE in 2003.



NSTAR Gas sales are positively impacted by colder weather because a substantial portion of its customer base uses natural gas for
space heating purposes.



Energy supply and other gas revenues primarily
represent charges to customers for the recovery of costs to the Company in order to acquire the natural gas in the marketplace and a charge for recovery of the Companys gas



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supplier service costs. The current gas rate structure of NSTAR Gas includes a gas adjustment clause, pursuant to which variations between actual gas costs
incurred and gas costs billed are deferred and refunded to or collected from customers in a subsequent period. The revenue increase of $28.8 million primarily reflects the impact of the higher cost of gas sold that reflected a weighted average cost
of gas per therm increase over the same period in 2003 of approximately 5.3%. These revenues are fully reconciled with the cost currently recognized by the Company and, as a result, do not have an effect on the Companys earnings.



Unregulated operations revenues



Unregulated operations revenues are derived from NSTARs businesses that include
district energy operations and telecommunications. Unregulated revenues were $109.1 million in 2004 compared to $113.2 million in 2003, a decrease of $4.1 million, or 4%. The decrease is primarily the result of the sale of Blackstone Station to
Harvard University in April 2003 partially offset by an increase in the revenues from electric and chilled water services and higher steam revenues resulting from colder weather and higher fuel costs.



Operating expenses



Purchased power costs were $1,347.9 million for 2004 compared to $1,329.8 million in 2003, an increase of $18.1 million, or 1%. The increase
is primarily the result of the higher costs of fuel, partially offset by the recognition of $44.2 million relating to the additional deferral of standard offer and default service supply costs. NSTAR Electric adjusts its rates to collect the costs
related to energy supply from customers on a fully reconciling basis. Due to this rate adjustment mechanism, changes in the amount of energy supply expense have no impact on earnings.



The cost of gas sold, representing NSTAR Gas supply expense, was $313.2 million for 2004 compared to $284.5 million in 2003, an
increase of $28.7 million, or 10%. Despite the lower volume of firm gas sales of 2.9%, the revenue increase reflects the higher costs of gas supply. NSTAR Gas maintains a flexible resource portfolio consisting of gas supply contracts, transportation
contracts on interstate pipelines, market area storage and peaking services. However, these expenses are also fully reconciled to the current level of revenues collected and have no impact on earnings.



Operations and maintenance expense was $421.4 million in 2004 compared to $443.9 million in
2003, a decrease of $22.5 million, or 5%. The decrease primarily reflects the first full year of the Companys pension and PBOP rate mechanism. The mechanism was implemented in September 2003 and, at that time, the Company expensed
approximately $18.0 million of pension and PBOP costs, which were deferred during the first eight months of 2003. Expenses in 2004 reflect lower labor and labor-related costs as well as the absence in 2004 of operation and maintenance costs
associated with Blackstone Station, which was sold in April 2003.



Depreciation
and amortization expense was $246.9 million in 2004 compared to $235.5 million in 2003, an increase of $11.4 million or 5%. The increase primarily reflects higher depreciable distribution and transmission plant in service, an increase to the
transmission depreciation rate, and increased expense related to software and merger costs to achieve amortization.



DSM and renewable energy programs expense was $67.3 million in 2004 compared to $66.2 million in 2003, an increase of $1.1 million, or 2%, which are consistent with the
collection of conservation and renewable energy revenues. These costs are in accordance with program guidelines established by the MDTE and are collected from customers on a fully reconciling basis plus a small incentive return.



Property and other taxes were $103.1 million in 2004 compared to $97.8 million in 2003, an
increase of $5.3 million, or 5%. This increase was due to higher overall municipal property taxes of $5.1 million caused primarily by higher assessments. Higher property taxes are primarily due to increased plant investment and increased rates



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##### Table of Contents

associated with legislation passed in Massachusetts allowing for the temporary shift of property tax burdens from residential to commercial property owners,
in particular, in the City of Boston.



Income taxes attributable to operations
were $116.2 million in 2004 compared to $121.4 million in 2003, a decrease of $5.2 million, or 4%. Despite higher pre-tax income in 2004, incomes taxes decreased due to the reversal of state tax reserves as a result of resolution of prior audit
periods and permanent tax benefits related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The tax benefit related to the Act will not impact NSTARs results of operations as these tax benefits are
incorporated into the Companys pension and PBOP rate adjustment mechanism.



Other income, net



Other income, net was approximately $7.3
million in 2004 compared to $14.4 million in 2003, a decrease in other income of $7.1 million. The decrease is primarily due to the absence in 2004 of the recognition of $4.6 million in tax benefits related to deferred tax valuation allowance
adjustments recognized in 2003 and the 2003 sale of Blackstone Station to Harvard University that resulted in a pre-tax gain of $1.3 million. In 2004, other income includes proceeds from an executive life insurance policy of $1.2 million, $1.7
million in employee-related contract fees received associated with the operating agreement with Harvard University related to Blackstone Station and higher interest income on investments of $1 million.



Other deductions, net



Other deductions, net were approximately $1.5 million in 2004 compared to $6.2 million in 2003, including write-down of RCN investment, net.
The $4.7 million decrease in other deductions in 2004 was due primarily to the absence of the RCN abandonment charge of $6.8 million (pre-tax) in 2003.



Interest charges



Interest on long-term debt and transition property securitization certificates was $147.3 million in 2004 compared to $153.7 million in 2003, a decrease of $6.4 million, or 4%. This decrease in interest expense
primarily reflects the retirement of Boston Edisons $181 million 7.80% Debentures on March 15, 2004 that lowered expense by $11.2 million, the absence of $2.1 million of interest expense in 2004 resulting from the retirement of Boston
Edisons $150 million 6.80% Debentures in March 2003, and the lower principal balance of transition property securitization certificates outstanding that resulted in reduced interest expense of $4.6 million. Securitization interest represents
interest on debt of BEC Funding collateralized by the future income stream associated primarily with the stranded costs of the Pilgrim Unit divestiture. These certificates are non-recourse to Boston Edison. Partially offsetting these interest
expense declines was additional interest expense of $10.3 million on Boston Edisons $300 million, 4.875% Debenture, issued on April 16, 2004 and an increase in interest expense of $1.4 million on ComElectrics Term Loan issued on May 14,
2003 ($150 million, three-year, variable rate); (3.0275% at December 31, 2004).



Short-term and other interest expense was $7.4 million in 2004 compared to $8.0 in 2003, a decrease of $0.6 million, or 8%. The decrease in short-term and other interest expense primarily relates to a reduction in bank service fees and
other charges ($1.9 million) resulting from a reduction in the level of NSTARs revolving line of credit. In addition, the decrease in short-term and other expenses includes a lower average level of debt outstanding of $164.9 million as
compared to $234.8 million for 2004 and 2003, respectively, slightly offset by higher bank borrowing rates that averaged 1.38% through December 2004 as compared to 1.28% in the same period in 2003. Taken together, these factors decreased short-term
borrowing costs by $0.6 million. Offsetting these decreases was an increase in regulatory interest due to higher customer deferral balances.



Allowance for funds used during construction/capitalized interest decreased $3.6 million, or 78%, in 2004, primarily due to the completion of construction in December
2003 of combustion turbines at AES MATEP facility.



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2003 compared to 2002



Earnings and Operations Overview



Earnings per common share were as follows:



|        |  |                          |      |      |   |          |  |     
|------- |  | ------------------------ | ---- | ---- | - | -------- |  | ----
|        |  | Years ended December 31,
|        |  | 2003                     |      | 2002 |   | % Change
|Basic   |  | $                        | 3.42 |      | $ | 3.05     |  | 12.1
|Diluted |  | $                        | 3.40 |      | $ | 3.03     |  | 12.2



Net income was $181.6 million for 2003
compared to $161.7 million for 2002. Three factors that contributed to the $19.9 million, or 12.3%, increase in 2003 earnings include increased retail electric and firm gas sales of 3.0% and 14.7%, respectively, as compared to 2002, interest savings
on the Companys outstanding indebtedness due to lower short-term and long-term interest and a lower level of borrowing in 2003, as well as a reduction in the impairment charges related to NSTARs investment in RCN Corporation (RCN) from
2002 to 2003.



NSTAR was able to achieve the earnings growth despite an
increase in operation and maintenance expenses. The primary factor for the $12.2 million increase in these expenses from 2002 was higher benefit costs. These costs were somewhat mitigated, as a result of a MDTE order, effective September 1, 2003,
which allowed the Company to defer approximately $9 million through December 31, 2003 in increased pension and other postretirement benefit costs. See Critical Accounting Policies and Estimates, Pension and Other Postretirement
Benefits, in this MD&A for more information on the MDTE order.



From a
cash flow perspective, NSTAR generated cash from operations sufficient to fund approximately $308 million of net capital expenditures and approximately $116 million of cash dividends. In comparison to the prior year, cash from operations decreased
primarily due to the timing of the collection of energy costs and increased contributions to NSTARs pension and PBOP plans. The Companys capital expenditures contributed to NSTARs solid operational performance in reliability,
restoration, and customer service measurements. These measurements are reflected in NSTARs MDTE service quality indicator filings, which indicated that NSTAR has exceeded its service quality measures and, therefore, not subject to penalties
for both 2003 and 2002. Cash expended for financing activities primarily reflect the payment of debt service requirements and dividends to shareholders.



Energy sales and weather



The following is a summary of retail electric and firm gas energy sales for the years indicated:



|                            |  |                          |  |            |  |          |  
|--------------------------- |  | ------------------------ |  | ---------- |  | -------- | -
|                            |  | Years ended December 31, | 
|                            |  | 2003                     |  | 2002       |  | % Change |  
|Retail Electric Sales - MWH |  |                          |  |            |  |          |  
|Residential                 |  | 6,492,738                |  | 6,116,906  |  | 6.1      |  
|Commercial                  |  | 12,417,719               |  | 12,089,839 |  | 2.7      |  
|Industrial                  |  | 1,694,184                |  | 1,797,718  |  | (5.8     | )
|Other                       |  | 170,012                  |  | 171,527    |  | (0.9     | )
|                            |  |                          |  |            |  |          |  
|Total retail sales          |  | 20,774,653               |  | 20,175,990 |  | 3.0      |  
|                            |  |                          |  |            |  |          |  
|                            | 
|                            |  | Years ended December 31, | 
|                            |  | 2003                     |  | 2002       |  | % Change |  
|Firm Gas Sales - BBTU       |  |                          |  |            |  |          |  
|Residential                 |  | 24,062                   |  | 20,913     |  | 15.1     |  
|Commercial                  |  | 16,152                   |  | 14,914     |  | 8.3      |  
|Industrial and other        |  | 8,175                    |  | 6,362      |  | 28.5     |  
|                            |  |                          |  |            |  |          |  
|Total firm sales            |  | 48,389                   |  | 42,189     |  | 14.7     |  
|                            |  |                          |  |            |  |          |  



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In terms of customer sectors, industrial sales are less sensitive to weather while residential and commercial sales are
influenced by temperature extremes. In addition to unseasonably cold winter weather and cool spring and summer conditions in 2003, the increase in sales is attributable in part to further home and commercial building and expansion of existing units
and the resulting extension of residential and commercial energy uses. Residential and commercial customers were approximately 31% and 59%, respectively, of NSTARs total sales mix for 2003 and provided 45% and 49% of distribution revenues,
respectively. Industrial sales are primarily influenced by national and global economic conditions and sales to these customers declined in 2003 primarily due to a slowdown in economic conditions that led to reduced production or facility closings.



NSTAR forecasts its electric and gas sales based on normal weather conditions.
Actual results may differ from those projected due to actual weather conditions above or below normal weather levels, and other factors. Refer to Cautionary Statement in this section.



|                                       |  |       |    |  |       |    |  |                     
|-------------------------------------- |  | ----- | -- |  | ----- | -- |  | --------------------
|                                       |  | 2003  |    |  | 2002  |    |  | Normal30-YearAverage
|Heating degree-days                    |  | 6,263 |    |  | 5,658 |    |  | 5,944               
|Percentage change from prior year      |  | 10.7  | %  |  | 0     | %  |  |                     
|Percentage change from 30-year average |  | 5.4   | %  |  | (4.8  | )% |  |                     
|                                       |  |       |   
|Cooling degree-days                    |  | 755   |    |  | 972   |    |  | 777                 
|Percentage change from prior year      |  | (22.3 | )% |  | 18.2  | %  |  |                     
|Percentage change from 30-year average |  | (2.8  | )% |  | 25.1  | %  |  |                     



Weather conditions impact electric
and, to a greater extent during the winter, gas sales in NSTARs service area. The first quarter of 2003 was significantly colder than the same period in 2002, followed by continued below normal temperatures for the second and third quarters,
and warmer than prior year and normal conditions by 11.2% and 4.0% in the fourth quarter of 2003, respectively. The comparative information above relates to heating and cooling degree-days for 2003 and 2002 and the number of degree-days in a
normal year as represented by a 30-year average. A degree-day is a unit measuring how much the outdoor mean temperature falls below (heating degree-day) or rises above (cooling degree-day) a base of 65 degrees. Each degree
below or above the base temperature is measured as one degree-day.



Operating revenues



Operating revenues for 2003 increased 8.2%
from 2002 as follows:



|                                     |      |   |         |  |        |                     |  |         |       |   |  |       |  
|------------------------------------ | ---- | - | ------- |  | ------ | ------------------- |  | ------- | ----- | - |  | ----- | -
|(in millions)                        |      |   |         |  |        | Increase/(Decrease) | 
|                                     | 2003 |   | 2002    |  | Amount |                     |  | Percent |      
|Electric revenues                    |      |   |         |  |        |                     |  |         |       |   |  |       |  
|Retail distribution and transmission |      | $ | 860.7   |  | $      | 810.9               |  | $       | 49.8  |   |  | 6.1   |  
|Energy, transition and other         |      |   | 1,451.1 |  |        | 1,380.5             |  |         | 70.6  |   |  | 5.1   |  
|                                     |      |   |         |  |        |                     |  |         |       |   |  |       |  
|Total retail                         |      |   | 2,311.8 |  |        | 2,191.4             |  |         | 120.4 |   |  | 5.5   |  
|Wholesale                            |      |   | 21.5    |  |        | 64.2                |  |         | (42.7 | ) |  | (66.5 | )
|                                     |      |   |         |  |        |                     |  |         |       |   |  |       |  
|Total electric revenues              |      |   | 2,333.3 |  |        | 2,255.6             |  |         | 77.7  |   |  | 3.4   |  
|                                     |      |   |         | 
|Gas revenues                         |      |   |         |  |        |                     |  |         |       |   |  |       |  
|Firm and transportation              |      |   | 149.4   |  |        | 131.1               |  |         | 18.3  |   |  | 14.0  |  
|Energy supply and other              |      |   | 315.8   |  |        | 200.7               |  |         | 115.1 |   |  | 57.3  |  
|                                     |      |   |         |  |        |                     |  |         |       |   |  |       |  
|Total gas revenues                   |      |   | 465.2   |  |        | 331.8               |  |         | 133.4 |   |  | 40.2  |  
|                                     |      |   |         | 
|Unregulated operations revenues      |      |   | 113.2   |  |        | 103.2               |  |         | 10.0  |   |  | 9.7   |  
|                                     |      |   |         |  |        |                     |  |         |       |   |  |       |  
|Total operating revenues             |      | $ | 2,911.7 |  | $      | 2,690.6             |  | $       | 221.1 |   |  | 8.2   |  
|                                     |      |   |         |  |        |                     |  |         |       |   |  |       |  



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Electric revenues



Electric retail distribution revenues primarily represent charges to customers for the Companys recovery of its capital investment,
including a return component, and operation and maintenance related to its electric distribution infrastructure. The transmission revenue component represents charges to customers for the recovery of costs to move the electricity over high voltage
lines from the generator to the Companys substations. The increase in retail revenues primarily reflects the 3% increase in retail MWH sales. Retail electric revenues for 2003 also include approximately $13 million in carrying charges on the
Companys average net prepaid pension and PBOP balances, as allowed under an order from the MDTE in 2003.



NSTARs largest earnings sources are the revenues derived from distribution rates approved by the MDTE. The level of distribution revenues is affected by weather conditions and the economy. Weather conditions
affect sales to NSTARs residential and small commercial customers. Economic conditions affect NSTARs large commercial and industrial customers.



Energy, transition and other revenues primarily represent charges to customers for the recovery of costs incurred by the Company in order to acquire the energy supply on
behalf of its customers and a transition charge for recovery of the Companys prior investments in generating plants and the costs related to long-term power contracts. The energy supply revenues relate to customers being provided energy supply
under either standard offer or default service. Energy supply contract prices vary among the NSTAR Electric companies and for standard offer and default service customers. However, the retail revenues related to standard offer and default services
are fully reconciled to the costs incurred and have no impact on NSTARs consolidated net income. Furthermore, energy and transition revenues are fully reconciled with the cost currently recognized by the Company and, as a result, do not have
an effect on the Companys earnings. Other revenues primarily relate to the Companys ability to effectively reduce stranded costs (mitigation incentive) and rental revenue from electric property.



Wholesale revenues relate to services provided to municipalities and certain other
governmental authorities. This decrease in wholesale revenues reflects the expiration of two wholesale power supply contracts in 2003 and three other contracts during 2002. After October 31, 2005, NSTAR Electric will no longer have contracts for the
supply of wholesale power. Amounts collected from wholesale customers are credited to retail customers through the transition charge. Therefore, the expiration of these contracts will have no impact on results of operations. In October 2004, a
municipal wholesale electric contract expired resulting in a decline in wholesale revenues and sales.



Gas revenues



Firm and transportation gas revenues primarily represent charges to customers for NSTAR Gas recovery of costs of its capital investment in its gas infrastructure,
including a return component, and for the recovery of costs for the ongoing operation and maintenance of that infrastructure. The transportation revenue component represents charges to customers for the recovery of costs to move the natural gas over
pipelines from gas suppliers to take stations located within NSTAR Gas service area. The $18.3 million increase in firm and transportation revenues is attributable to the 14.7% increase in energy sales due to the significantly colder winter
weather, and additional customers. Firm gas revenues also include approximately $3 million in carrying charges on the Companys average net prepaid pension and PBOP balances, as allowed under an order from the MDTE in 2003.



NSTAR Gas sales are positively impacted by colder weather because a substantial portion
of its customer base uses natural gas for space heating purposes.



Energy
supply and other gas revenues primarily represent charges to customers for the recovery of costs to the Company in order to acquire the natural gas in the marketplace and a charge for recovery of the Companys gas supplier service costs. This
revenue increase of $115.1 million primarily reflects the higher costs of gas supply that reflected a weighted average cost of gas per therm increase over 2002 of approximately 88%. These revenues are fully reconciled with the cost currently
recognized by the Company and, as a result, do not have an effect on the Companys earnings.



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Unregulated operations revenues



Unregulated operations revenues are derived from NSTARs businesses that include district energy operations, telecommunications, and
liquefied natural gas service. Unregulated revenues were $113.2 million in 2003 compared to $103.2 million in 2002, an increase of $10.0 million, or 10%. The increase in unregulated revenues is primarily the result of an increase in the rates for
electric and chilled water services and higher steam revenues resulting from the significantly colder weather and higher fuel costs.



Operating expenses



Purchased power costs were $1,329.8 million for 2003 compared to $1,236.3 million in 2002, an increase of $93.5 million, or 8%. The increase is primarily the result of increased sales and the higher costs of fuel,
partially offset by the recognition of $29.2 million relating to the deferred standard offer and default service supply costs for current period under-collection of these costs. NSTAR Electric adjusts its 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.



The cost of gas sold, representing NSTAR Gas supply expense, was $284.5 million for 2003 compared to $176.5 million in 2002, an
increase of $108.0 million, or 61%, due to recognition of the higher costs of gas supply and the significant increase in sales. NSTAR Gas maintains a flexible resource portfolio consisting of gas supply contracts, transportation contracts on
interstate pipelines, market area storage and peaking services. However, these expenses are also fully reconciled to the current level of revenues collected.



Operations and maintenance expense was $443.9 million in 2003 compared to $431.7 million in 2002, an increase of $12.2 million, or 3%. This increase primarily reflects a
higher overall level of pension and PBOP costs of approximately $33 million. This increase was somewhat mitigated, effective September 1, 2003, as a result of a MDTE order, which allowed NSTAR to defer approximately $9 million through December 31,
2003 of the increased pension and other postretirement benefits expense. This increase was partially offset by the reduction in operations and maintenance expense as the Company benefited from improvements made in electric distribution services in
2002 and overall cost reduction initiatives in 2003. Also, bad debt expense increased by $2.6 million due to higher retail revenue and receivables outstanding.



Depreciation and amortization expense was $235.5 million in 2003 compared to $239.2 million in 2002, a decrease of $3.7 million or 2%. The decrease primarily reflects
the absence in 2003 of $7.3 million in accelerated amortization of regulatory assets associated with the Seabrook generating unit sale in 2002, partially offset by higher depreciable plant in service.



DSM and renewable energy programs expense was $66.2 million in 2003 compared to $69.0 million
in 2002, a decrease of $2.8 million, or 4%, which are consistent with the collection of conservation and renewable energy revenues. These costs are in accordance with program guidelines established by the MDTE and are collected from customers on a
fully reconciling basis plus a small incentive return.



Property and other
taxes were $97.8 million in 2003 compared to $97.2 million in 2002, an increase of $0.6 million, or 1%. This increase was due to higher overall municipal property taxes of $2.1 million caused primarily by higher property assessments, capital
additions and tax rates in the City of Boston, partially offset by lower payroll charges.



Income taxes attributable to operations were $121.4 million in 2003 compared to $107.1 million in 2002, an increase of $14.3 million, or 13%, reflecting higher pre-tax operating income in 2003 and the absence of tax
benefits related to the sale of the Seabrook generating unit in 2002, which reduced income tax expense by approximately $4 million in 2002.



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Other income, net



Other income, net was $14.4 million in 2003 compared to $22.4 million in 2002, a decrease in other income of $8.0 million. The decrease in 2003 income was due primarily
to the absence of $4.9 million in gains realized in 2002 on the sale of demutualized insurance company common shares and the recognition of investment tax credits of $7.3 million as a result of the sale of the Seabrook generating unit in 2002,
offset by the incremental benefit recognized related to deferred tax valuation allowance adjustments recognized in 2003 of approximately $4.6 million. Also, in 2003, other income, net includes the sale of Blackstone Station that resulted in a pretax
gain of $1.3 million.



Other deductions, net



Other deductions, net, including write-down of RCN investment, net, were $6.2 million in
2003 and $19.7 million in 2002. In addition to the $4.5 million and the $17.7 million write-downs of the RCN investment in 2003 and 2002, other deductions in 2002 amounted to $2 million. The $4.2 million increase in other deductions in 2003 was due
primarily to the RCN abandonment charge of $6.8 million (pre-tax). Offsetting this increase was the absence in 2003 of a $2 million accrual for shutdown costs recorded in 2002 for the Northwind district energy facility for expected equipment removal
costs.



Interest charges



Interest on long-term debt and transition property securitization certificates was $153.7
million in 2003 compared to $152.6 million in 2002, an increase of $1.1 million, or 1%. This increase in interest expense primarily reflects the impact of the October 15, 2002 Boston Edison issuance of $400 million of 4.875% 10-year debentures and
$100 million of 3-year floating rate debentures priced at three month LIBOR plus 50 basis points (1.65% at December 31, 2003). Also, contributing to this increase was ComElectrics issuance of a $150 million variable rate (1.895% at December
31, 2003) Term Loan on May 14, 2003. These new debt issuances increased interest expense by $18.4 million in 2003. Partially offsetting these increases was the absence in 2003 of $11.6 million in interest due to Boston Edisons early redemption
of its $60 million 8.25% Debentures in September 2002 and its $150 million 6.80% Debentures retired in March 2003 and scheduled repayments of its transition property securitization certificates of $68.7 million that resulted in reduced interest
expense of $4.4 million. Securitization interest represents interest on debt collateralized by the future income stream associated primarily with the stranded costs of the Pilgrim Unit divestiture. These certificates are non-recourse to Boston
Edison.



Short-term and other interest expense was $8 million in 2003 compared
to $22.8 million in 2002, a decrease of $14.8 million, or 65%. This decrease is primarily attributable to both lower borrowing rates and a lower average level of short-term debt outstanding that averaged $234.8 million and $494.7 million in 2003 and
2002, respectively. Interest rates on these borrowings averaged 1.28% and 1.89% for 2003 and 2002, respectively.



The increase in long-term debt interest expense and the decrease in short-term debt interest expense is primarily due to the fact that NSTAR has refinanced some
short-term debt with long-term debt in order to take advantage of favorable interest rates.



Allowance for funds used during construction/capitalized interest increased $1.7 million, or 59%, primarily due to a higher average balance of construction work in progress during the year due to the construction of
new combustion turbines at AES MATEP facility.



Liquidity and Capital
Resources



A major driver to NSTARs liquidity is the level of plant
expenditures. Plant expenditures currently forecasted for 2005 are $398 million, consisting of approximately $392 million for electric and gas operations and $6 million for capital requirements of non-utility ventures. The plant expenditure level
over the following four years (2006-2009) is currently forecasted to aggregate approximately $1.1 billion.



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Forecasted plant expenditures include NSTARs 345kV transmission project that, in the aggregate, is expected to
total $200 million. A significant portion of these costs will be incurred in 2005 and 2006. NSTAR has obtained regulatory approval to construct a 345kV transmission line from Stoughton, Massachusetts, a southern suburb of Boston, to South Boston in
order to assure continued reliability of service and improve power import capacity in the Northeast Massachusetts area (NEMA). Construction is set to begin in the first quarter of 2005, subject to final permitting. The new transmission line is
anticipated to be placed in service during the summer of 2006. This project is a regional transmission investment and, as a result, the cost will be shared by all of New England and recovered in rates by NSTAR through wholesale and retail
transmission rates.



In addition to plant expenditures, NSTARs primary
estimated uses of cash for each of the years presented below include long-term debt principal and interest payments, minimum lease commitments, electric contractual capacity charge obligations, natural gas contractual agreements and purchase power
contract buy-out/restructuring obligations.



|                                                            |  |      |     |      |   |      |  |      |     |      |   |                 |  |       |     |  |   |       |  |   |      
|----------------------------------------------------------- |  | ---- | --- | ---- | - | ---- |  | ---- | --- | ---- | - | --------------- |  | ----- | --- |  | - | ----- |  | - | -----
|(in millions)                                               |  | 2005 |     | 2006 |   | 2007 |  | 2008 |     | 2009 |   | YearsThereafter |  | Total
|Long-term debt                                              |  | $    | 108 |      | $ | 179  |  | $    | 15  |      | $ | 17              |  | $     | 7   |  | $ | 1,588 |  | $ | 1,914
|Interest obligation on long-term debt                       |  |      | 117 |      |   | 111  |  |      | 106 |      |   | 105             |  |       | 104 |  |   | 337   |  |   | 880  
|Transition property securitization *                        |  |      | 68  |      |   | 69   |  |      | 69  |      |   | 68              |  |       | 68  |  |   | 35    |  |   | 377  
|Interest obligation on transition property securitization * |  |      | 25  |      |   | 20   |  |      | 16  |      |   | 11              |  |       | 6   |  |   | 1     |  |   | 79   
|Leases                                                      |  |      | 20  |      |   | 14   |  |      | 13  |      |   | 11              |  |       | 9   |  |   | 39    |  |   | 106  
|Electric capacity obligations **                            |  |      | 29  |      |   | 2    |  |      | 2   |      |   | 2               |  |       | 2   |  |   | 24    |  |   | 61   
|Gas contractual obligations **                              |  |      | 48  |      |   | 45   |  |      | 36  |      |   | 35              |  |       | 34  |  |   | 92    |  |   | 290  
|Purchase power buy-out obligations **                       |  |      | 145 |      |   | 156  |  |      | 160 |      |   | 162             |  |       | 142 |  |   | 346   |  |   | 1,111
|                                                            |  |      |     |      |   |      |  |      |     |      |   |                 |  |       |     |  |   |       |  |   |      
|                                                            |  | $    | 560 |      | $ | 596  |  | $    | 417 |      | $ | 411             |  | $     | 372 |  | $ | 2,462 |  | $ | 4,818
|                                                            |  |      |     |      |   |      |  |      |     |      |   |                 |  |       |     |  |   |       |  |   |      

---

|* | Reflects securities issued by BEC Funding LLC, a subsidiary of Boston Edison. BEC Funding LLC recovers the principal and interest obligations for its transition property
securitization bonds from customers of Boston Edison through a component of Boston Edisons transition charge and, as a result, these payment obligations do not affect NSTARs overall cash flow. During the first half of 2005, NSTAR expects
to issue additional transition property securitization bonds through BEC Funding II, LLC, a subsidiary of Boston Edison and CEC Funding, LLC, a subsidiary of ComElectric. This new obligation is not included in the table above as the exact amount of
the obligation and the resulting yearly principal and interest payment requirements are not yet finalized.
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|** | Reflects obligations for purchase power and the cost of gas. Boston Edison, Cambridge Electric and ComElectric recover capacity and buy-out/restructuring obligations from customers
through a component of their transition charges and, as a result, these payment obligations do not affect NSTARs overall cash flow. NSTAR Gas recovers its contractual obligations from customers through its seasonal cost of gas adjustment
clause and, as a result, these payment obligations do not affect NSTARs overall cash flow.
|-- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Current Cash Flow Activity



Operating
activities in 2004 provided $437.5 million of cash. The Company used $303.2 million in its investing activities, primarily to fund $313.4 million of plant expenditures, which included system reliability infrastructure improvement projects incurred
by NSTAR Electric and NSTAR Gas operations. Additionally, the Company used $138.3 million in financing activities to primarily fund $120 million of dividends.



Operating Activities



The net cash provided by 2004 operating activities increased $12.2 million from 2003 to $437.5 million. Major drivers to cash provided by operating activities are working
capital and energy cost recoveries. From a working capital perspective, accounts payable increased approximately $15 million due to the timing of energy supply



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invoices and Company benefit plan contributions decreased approximately $59 million year-to-year. NSTAR contributed approximately $43 million to its pension
plan and approximately $20 million to its other postretirement benefit plans in 2004. NSTAR currently anticipates that it will contribute approximately $35 million to its pension plan and approximately $20 million to its other postretirement benefit
plans in 2005.



Offsetting the positive working capital components were
decreased energy cost recoveries year-to-year by approximately $43 million. There is no impact to earnings, as energy costs are fully recoverable from customers through the transition charge.



During 2003 and 2004, NSTAR has benefited from bonus depreciation for income tax purposes
(between 30% and 50% depreciation on new capital additions). As a result, NSTARs deferred income taxes have increased. As of December 31, 2004, the bonus depreciation rules have generally expired. Therefore, in 2005 and beyond, the cash flow
benefit from bonus depreciation will be limited to certain qualified projects.



Investing Activities



The net cash used
in investing activities in 2004 of $303.2 million consists primarily of capital expenditures related to infrastructure investments in transmission and distribution systems.



Financing Activities



The net cash used in financing activities in 2004 of $138.3 million reflects long-term debt redemptions and sinking funds payments of $258.4 million, dividends paid of
$119.8 million and a reduction in short-term borrowings since December 2003 of $77.7 million as a result of the $300 million financing by Boston Edison in April 2004.



NSTARs banking arrangements provide for daily cash transfers to our disbursement accounts as vendor checks are presented for payment
and where the right of offset does not exist among accounts. Changes in the balances of the disbursement accounts are reflected in financing activities in the accompanying Statement of Cash Flows.



Additionally, beginning in August 2004, NSTAR began issuing common shares for cash as part of
its Dividend Reinvestment and Direct Common Shares Purchase Plan. As of December 31, 2004, NSTAR has issued approximately 156,000 common shares and has received approximately $7.6 million as a result of the plan.



Short-Term Financing Activities



NSTARs short-term debt decreased by $77.7 million to $161.4 million at December 31,
2004 as compared to $239.1 million at December 31, 2003. The decrease resulted primarily from the proceeds of the $300 million financing being used to pay down short-term debt balances.



Previously, on March 16, 2004, Boston Edison redeemed the entire $181 million aggregate principal amount of its 7.80% Debentures due March
15, 2023. The redemption included payment of an approximate $6.1 million premium plus accrued interest.



Long-Term Financing Activities



In 2003, NSTAR Electric initiated a process to auction off certain purchase power agreements under which NSTAR Electric had entitlements to approximately 1,100 MW of
capacity under long-term contracts with non-utility generators. The auction was intended to further NSTAR Electrics efforts to mitigate stranded costs, which continue to be recovered from customers. One contract in which NSTAR Electric had
entitlements to approximately 300 MW of the 1,100 MW of capacity, originally included in the auction, expired on December 31, 2004. Also in 2004, NSTAR Electric executed agreements to buy-out or restructure twelve of its



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purchase power agreements. These buy-out/restructuring agreements provide no economic benefit to NSTAR Electric and, therefore, the agreements contract
termination costs will be recorded on the accompanying Consolidated Financial Statements. These agreements constitute approximately 685 MW of the 1,100 MW of capacity, originally included in the auction, and reduce the amount of NSTAR
Electrics future exposure to the above market costs that NSTAR Electric will collect from its customers through its transition charges. As of December 31, 2004, four of these agreements have received MDTE approval and have been recognized. Two
of the four agreements require NSTAR Electric to make monthly payments through December 2008 totaling approximately $80 million. The other two agreements require NSTAR Electric to make monthly payments through September 2011 totaling approximately
$125 million.



On January 7, 2005, NSTAR Electric received approval from the
MDTE for an additional four agreements that are anticipated to be completed by February 2005. These four agreements were binding as of December 31, 2004 but were contingent upon regulatory approval. Since the contingency has been removed during
February 2005, NSTAR recorded the contract termination costs as of December 31, 2004. One of the four agreements requires NSTAR Electric to make net monthly payments through September 2011 totaling approximately $416 million. The other three
agreements require NSTAR Electric to make net monthly payments through September 2016 totaling approximately $490 million. NSTAR Electric anticipates making these cash payments from funds generated from operations and will be fully recovered through
NSTAR Electrics transition charge.



The total amount currently recognized
for obligations relating to eight of the twelve contracts is approximately $852 million (in present day dollars); approximately $171 million as a component of current liabilities-power contracts and $681 million as a component of Deferred
credits-power contracts on the accompanying Consolidated Balance Sheets. NSTAR Electric has recorded a corresponding regulatory asset to reflect the full future recovery of these payments through its transition charge. This recognition represents a
non-cash increase in assets and liabilities.



Also in January 2005, the MDTE
approved the remaining four contracts with two suppliers that reduced the overall amount of transition costs to be paid for above market contracts. The four contracts with the two suppliers are buy-out arrangements whereby NSTAR Electric has
committed to pay amounts for the full release of its obligation under previous purchase power agreements. On August 31, 2004, NSTAR Electric filed with the MDTE a proposed financing plan that seeks approval for full recovery of these buy-out costs
and the issuance of $674.5 million in transition property securitization bonds to provide the funds for these four buy-out agreements. The MDTE approved the financing plan in January 2005. On February 15, 2005, the bonds were priced at a weighted
average yield of 4.15%. NSTAR expects the securitization financing to close in March 2005.



Management continuously reviews its capital expenditure and financing programs. These programs and, therefore, the forecasts included in NSTARs 2004 Form 10-K are subject to revision due to changes in regulatory
requirements, operating requirements, environmental standards, availability and cost of capital, interest rates and other assumptions.



Sources of Additional Capital and Financial Covenant Requirements



NSTAR and Boston Edison have no financial covenant requirements under their respective long-term debt arrangements. ComElectric, Cambridge Electric and NSTAR Gas have
financial covenant requirements under their long-term debt arrangements and were in compliance at December 31, 2004 and 2003. NSTARs long-term debt other than the Mortgage Bonds/Notes of NSTAR Gas and Medical Area Total Energy Plant, Inc., a
wholly owned subsidiary of AES, is unsecured.



The Transition Property
Securitization Certificates issued by Boston Edisons subsidiary, BEC Funding, LLC, are collaterized with a securitized regulatory asset that was sold to BEC Funding with a balance of $357.2 million and $425.4 million as of December 31, 2004
and 2003, respectively. Boston Edison, as servicing agent for BEC Funding, collected $96.0 million in 2004. These collected funds are remitted daily to an indenture trustee for BEC Funding. These Certificates are non-recourse to Boston Edison.



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##### Table of Contents

In November 2004, NSTAR restructured its three-year, $175 million revolving credit agreement that was set to expire on
November 15, 2005 into a five-year, $175 million revolving credit agreement that expires in November 2009. At December 31, 2004 and 2003, there were no amounts outstanding under the current and previous revolving credit agreement. This credit
facility serves as a backup to NSTARs $175 million commercial paper program that, at December 31, 2004 and 2003, had $5 million and $1.5 million outstanding, respectively. Under the terms of the current credit agreement, NSTAR is required to
maintain a maximum total consolidated debt to total capitalization ratio of not greater than 65% at all times, excluding Transition Property Securitization Certificates, and excluding Accumulated other comprehensive income (loss) from Common equity.
The previous arrangement also required NSTAR to maintain a ratio of consolidated earnings before interest and taxes to consolidated total interest expense of not less than 2 to 1 for each period of four consecutive fiscal quarters. Commitment fees
must be paid on the total agreement amount. At December 31, 2004 and 2003, NSTAR was in full compliance with all of the aforementioned covenants.



In December 2003, Boston Edison filed a shelf registration with the SEC to allow Boston Edison to issue up to $500 million in debt securities. The registration became
effective on January 9, 2004. On April 1, 2004, the MDTE approved the issuance by Boston Edison of up to $500 million of debt securities from time to time on or before December 31, 2005. On April 16, 2004, Boston Edison sold $300 million of ten-year
fixed rate (4.875%) Debentures under this shelf registration. The net proceeds were primarily used to repay outstanding short-term debt balances.



As of September 28, 2004, Boston Edison has approval from the FERC to issue short-term debt securities from time to time on or before December 31, 2006, with maturity
dates no later than December 31, 2007, in amounts such that the aggregate principal does not exceed $450 million at any one time. In addition, in November 2004, Boston Edison restructured its $350 million revolving credit agreement that expired in
November 2004 into a five-year, $350 million revolving credit agreement that expires in November 2009. However, unless Boston Edison receives necessary approvals from the MDTE, the credit agreement will expire 364 days from the date of the first
draw under the agreement. At December 31, 2004 and 2003, there were no amounts outstanding under the current and previous revolving credit agreements. This credit facility serves as backup to Boston Edisons $350 million commercial paper
program that had a $46.5 million and $182.5 million balance at December 31, 2004 and 2003, respectively. Under the terms of the current agreement, Boston Edison is required to maintain a consolidated maximum total debt to capitalization ratio of not
greater than 65% at all times, excluding Transition Property Securitization Certificates, and excluding Accumulated other comprehensive income (loss) from Common equity. The previous agreement required a total debt to capitalization ratio of not
greater than 60%. At December 31, 2004 and 2003, Boston Edison was in full compliance with all of its covenants in connection with its short-term credit facilities.



In addition, as of December 31, 2004, ComElectric, Cambridge Electric and NSTAR Gas, collectively, have $145 million available under several
lines of credit and had $109.9 million and $55.1 million outstanding under these lines of credit at December 31, 2004 and 2003, respectively. As of September 28, 2004, ComElectric and Cambridge Electric have FERC authorization to issue short-term
debt securities from time-to-time on or before November 30, 2006 and June 27, 2006, with maturity dates no later than November 30, 2007 and June 27, 2007, respectively, in amounts such that the aggregate principal does not exceed $125 million and
$60 million, respectively, at any one time. NSTAR Gas is not required to seek approval from FERC to issue short-term debt.



On June 30, 2004, NSTAR filed an S-3 Registration Statement with the SEC for the purpose of registering two million common shares in connection with the NSTAR Dividend
Reinvestment and Direct Common Shares Purchase Plan. The Registration Statement became effective on July 29, 2004. Since the effective date, NSTAR has issued approximately 156,000 shares under this registration and received approximately $7.6
million. Additionally, NSTAR issued approximately 86,000 shares as part of its Share Incentive Plan. No cash was received from this issuance.



On December 16, 2004, NSTAR announced its intention to split its common shares two-for-one, subject to market conditions and shareholder approval of an amendment to the
Companys Declaration of Trust that would



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increase the number of NSTARs authorized common shares, at the April 28, 2005 Annual Meeting of Shareholders.



Historically, NSTAR and its subsidiaries have had a variety of external sources of financing
available, as indicated above, at favorable rates and terms to finance its external cash requirements. However, the availability of such financing at favorable rates and terms depends heavily upon prevailing market conditions and NSTARs or its
subsidiaries financial condition and credit ratings.



An adverse change
in NSTARs or its subsidiaries credit ratings or market conditions could have an adverse impact on the terms and conditions upon which NSTAR or its subsidiaries have access to capital markets. Currently, NSTAR and its subsidiaries have
A level ratings at Standard & Poors, Moodys and Fitch Ratings with a stable outlook for NSTAR and its subsidiaries. NSTAR has no financial guarantees, commitments, debt or lease agreements that would require a change in
terms and conditions, such as acceleration of payment obligations, as a result of a change in its credit rating. However, NSTARs subsidiaries could be required to provide additional security for power supply contract performance, such as a
letter of credit for their pro-rata share of the remaining value of such contracts. Refer to Performance Assurances from Electricity and Gas Supply Agreements and Financial and Performance Guarantees as disclosed in this
MD&A.



NSTARs goal is to maintain a capital structure that preserves
an appropriate balance between debt and equity. Based on NSTARs key cash resources available as discussed above, management believes its liquidity and capital resources are sufficient to meet its current and projected requirements.



Other Events



On July 14, 2003, Mirant Corporation and certain of its subsidiaries (Mirant) filed
voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. Mirant currently supplies, among other services, standard offer service for approximately 12% of NSTAR Electrics standard offer load. Should Mirant fail to
perform under this agreement, NSTAR Electric would be required to seek replacement energy supply to meet its standard offer obligation. NSTARs current expectation is that Mirant will continue to perform under its agreements with NSTAR, and, as
a result, NSTAR does not expect the Mirant bankruptcy to have a material impact to its earnings or cash flows.



Performance Assurances from Electricity and Gas Supply Agreements



NSTAR Electric has contracted with a third party supplier to provide 100% of its standard offer service supply obligations through February 28, 2005. In addition, NSTAR Electric has entered into a number of short-term
power purchase agreements to meet its entire default service supply obligation, other than large customers, for the period January 1, 2005 through June 30, 2005 and for 50% of its obligation, other than large customers, for the second half of 2005.
NSTAR Electric has entered into a number of short-term power purchase agreements to meet its entire default service supply obligation for large customers through March 2005. These agreements are for a term of three to twelve months. NSTAR Electric
currently is recovering payments it is making to suppliers from its customers. Most of NSTAR Electrics power suppliers are either investment grade companies or are subsidiaries of larger companies with investment grade or better credit
ratings. In accordance with NSTARs Internal Credit Policy, and to minimize NSTAR Electric risk in the event the supplier encounters financial difficulties or otherwise fails to perform, NSTAR has financial assurances and guarantees that
include both parental guarantees and letters of credit in place from the parent company of the supplier. In addition, under these agreements, in the event that the supplier (or its parent guarantor) fails to maintain an investment grade credit
rating, it is required to provide additional security for performance of its obligations. In view of current volatility in the energy supply industry, NSTAR Electric is unable to determine whether its suppliers (or their parent guarantors) will
become subject to financial difficulties, or whether these financial assurances and guarantees are sufficient. In the event the supplier (or its guarantor) does not provide the required additional security within the required time frames, NSTAR
Electric may then terminate the agreement. In such event, NSTAR may be



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required to secure alternative sources of supply at higher or lower prices than provided under the terminated agreements. Some of these agreements include a
reciprocal provision, where in the event that an NSTAR Electric distribution company receives a downgrade, that company could be required to provide additional security for performance, such as a letter of credit.



Virtually all of NSTAR Gas firm gas supply agreements are short-term (less than one
year) and utilize market-based, monthly indexed pricing mechanisms so the financial risk to the Company would be minimal if a supplier were to fail to perform. However, in the event that a firm supplier does fail to perform under its firm gas supply
agreement pricing provisions, the Company would be entitled to any positive difference between the monthly supply price and the cost of replacement supplies.



The cost of gas procured for firm gas sales customers is recovered through a semi-annual cost of gas adjustment mechanism. Under MDTE regulations, interim adjustments to
the cost of gas may also be requested when the actual costs of gas supply vary from projections by more than 5%.



NSTAR Gas continually evaluates the financial stability of current and prospective gas suppliers. Firm suppliers are required to have and maintain investment grade credit
ratings or financial assurances and guarantees that include both parental guarantees and letters of credit in place from the parent company of the supplier and the firm gas supply agreements allow either party to require financial assurance, or, if
necessary, contract termination in the event that either party is downgraded below investment grade level and is unable to provide financial assurance acceptable to NSTAR Gas.



Financial and Performance Guarantees



On a limited basis, NSTAR and certain of its subsidiaries may enter into agreements providing financial assurance to third parties. Such agreements include letters of
credit, surety bonds, and other guarantees.



At December 31, 2004, outstanding
guarantees totaled $30.3 million as follows:



|                  |  |   |       
|----------------- |  | - | ------
|(in thousands)    |  |  
|Letters of Credit |  | $ | 5,560 
|Surety Bonds      |  |   | 15,281
|Other Guarantees  |  |   | 9,500 
|                  |  |   |       
|Total Guarantees  |  | $ | 30,341
|                  |  |   |       



The $5.6 million letter of credit is
for the benefit of a third party, as trustee in connection with the 6.924% Notes of one of NSTARs subsidiaries. The letter of credit is available if the subsidiary has insufficient funds to pay the debt service requirements. As of December 31,
2004, there have been no amounts drawn under this letter of credit.



As of
December 31, 2004, certain of NSTARs subsidiaries have purchased a total of $0.6 million of performance surety bonds for the purpose of obtaining licenses, permits and rights-of-way in various municipalities. In addition, NSTAR and certain of
its subsidiaries has purchased approximately $14.7 million in workers compensation self-insurer bonds. These bonds support the guarantee by NSTAR and certain of its subsidiaries to the Commonwealth of Massachusetts required as part of the
Companys workers compensation self-insurance program.



NSTAR and
its subsidiaries have also issued $9.5 million of residual value guarantees related to its equity interest in the Hydro-Quebec transmission companies.



Management believes the likelihood NSTAR would be required to perform or otherwise incur any significant losses associated with any of these guarantees is remote.



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Contingencies



Environmental Matters



As of December 31, 2004, NSTARs subsidiaries are involved in four 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 sometimes uncertainties associated with total remediation costs due to
the final selection of the specific cleanup technology and the particular characteristics of the different sites. Estimates of approximately $0.5 million and $0.7 million are included as liabilities in the accompanying Consolidated Balance Sheets at
December 31, 2004 and 2003, respectively.



In addition to the MCP sites, NSTAR
subsidiaries also face possible liability as a result of involvement in 15 multi-party disposal sites or third party claims associated with contamination remediation. NSTAR generally expects to have only a small percentage of the total potential
liability for these sites. Estimates of approximately $3.4 million are included as liabilities in the accompanying Consolidated Balance Sheets at December 31, 2004 and 2003.



The MCP and multi-party disposal site amounts have not been reduced by any potential rate recovery treatment of these costs or any potential
recovery from NSTARs insurance carriers. Prospectively, should NSTAR be allowed to collect these specific costs from customers, it would record an offsetting regulatory asset and record a credit to operating expenses equal to previously
expensed costs.



NSTAR Gas is participating in the assessment or remediation of
five 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, 2004 and 2003, NSTAR has recorded a liability of approximately $3.8 million and $4.4 million, respectively, as an estimate for site cleanup costs for
several MGP sites for which NSTAR Gas was previously cited as a potentially responsible party. A corresponding regulatory asset has been recorded that reflects the future rate recovery for these costs.



Estimates related to environmental remediation costs are reviewed and adjusted periodically
as further investigation and assignment of responsibility occurs and as either additional sites are identified or NSTARs responsibilities for such sites evolve or are resolved. NSTARs ultimate liability for future environmental
remediation costs may vary from these estimates. Based on NSTARs current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, NSTAR does not believe that these environmental remediation costs
will have a material adverse effect on NSTARs consolidated financial position, results of operations and cash flows for a reporting period.



Employees and Employee Relations



As of December 31, 2004, NSTAR had approximately 3,100 employees, including approximately 2,200, or 71%, who are represented by three units covered by separate collective
bargaining contracts.



NSTARs contract with Local 369 of the Utility
Workers Union of America, AFL-CIO, which represents approximately 1,900 employees, expires on May 15, 2005. Management has begun discussions with union officials for Local 369 for a new labor contract. Approximately 250 employees, represented by
Local 12004, United Steelworkers of America, AFL-CIO, have a contract that expires on March 31, 2006. Approximately 60 employees of Advanced Energy Systems MATEP subsidiary are represented by Local 877, the International Union of Operating
Engineers, AFL-CIO, under a contract that expires on September 30, 2006.



Management believes it has satisfactory relations with its employees.



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Fair Value of Financial Instruments



Carrying amounts and fair values of long-term indebtedness (excluding notes payable, including current maturities) as of December 31, 2004
and 2003, were as follows:



|                                                      |  |                |           |            |   |                |  |            |           |  |   |          
|----------------------------------------------------- |  | -------------- | --------- | ---------- | - | -------------- |  | ---------- | --------- |  | - | ---------
|                                                      |  | 2004           |           | 2003      
|(in thousands)                                        |  | CarryingAmount |           | Fair Value |   | CarryingAmount |  | Fair Value
|Long-term indebtedness (including current maturities) |  | $              | 2,250,647 |            | $ | 2,483,220      |  | $          | 2,209,585 |  | $ | 2,485,190



As discussed in the following section,
NSTARs exposure to financial market risk results primarily from fluctuations in interest rates.



|Item 7A. | Quantitative and Qualitative Disclosures About Market Risk
|-------- | ----------------------------------------------------------



Although NSTAR has material commodity purchase contracts, these instruments are not subject to market risk. NSTARs electric and gas distribution subsidiaries have
rate-making mechanisms that allow for the recovery of energy supply costs from customers, who make commodity purchases from NSTARs electric and gas subsidiaries, rather than from the competitive market. All energy supply costs incurred by
NSTARs electric and gas subsidiaries to provide electricity for retail customers purchasing standard offer service (which expires on February 28, 2005) and default service or retail gas customers are recovered on a fully reconciling basis.



In addition, NSTARs exposure to financial market risk results primarily
from fluctuations in interest rates. NSTAR is exposed to changes in interest rates primarily based on levels of short-term debt outstanding. The weighted average interest rates for long-term indebtedness, including current maturities were 6.23% and
6.45% in 2004 and 2003, respectively.



On May 14, 2003, ComElectric entered
into a $150 million, three-year variable rate unsecured Term Loan with a group of banks priced at LIBOR plus 62.5 basis points. An immediate change of one percent on this Term Loan would cause a change in interest expense of approximately $1.5
million per year.



On October 15, 2002, Boston Edison issued $100 million of
3-year floating rate debentures priced at LIBOR plus 50 basis points. An immediate change of one percent for these variable rate debentures would cause a change in interest expense of approximately $1 million per year.



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|Item 8. | Financial Statements and Supplementary Data
|------- | -------------------------------------------



NSTAR

Consolidated Statements of Income



|                                                                               |  |                                           |           |   |      |   |           |      |  |   |           |  
|------------------------------------------------------------------------------ |  | ----------------------------------------- | --------- | - | ---- | - | --------- | ---- |  | - | --------- | -
|                                                                               |  | Years ended December 31,                  |          
|                                                                               |  | 2004                                      |           |   | 2003 |   |           | 2002 | 
|                                                                               |  | (in thousands, except earnings per share) |          
|                                                                               |  |                                           |          
|Operating revenues                                                             |  | $                                         | 2,954,332 |   |      | $ | 2,911,711 |      |  | $ | 2,690,625 |  
|                                                                               |  |                                           |           |   |      |   |           |      |  |   |           |  
|Operating expenses:                                                            |  |                                           |           |   |      |   |           |      |  |   |           |  
|Purchased power and cost of gas sold                                           |  |                                           | 1,661,100 |   |      |   | 1,614,290 |      |  |   | 1,412,794 |  
|Operations and maintenance                                                     |  |                                           | 421,367   |   |      |   | 443,931   |      |  |   | 431,740   |  
|Depreciation and amortization                                                  |  |                                           | 246,944   |   |      |   | 235,516   |      |  |   | 239,233   |  
|Demand side management and renewable energy programs                           |  |                                           | 67,294    |   |      |   | 66,217    |      |  |   | 68,986    |  
|Property and other taxes                                                       |  |                                           | 103,061   |   |      |   | 97,837    |      |  |   | 97,204    |  
|Income taxes                                                                   |  |                                           | 116,238   |   |      |   | 121,409   |      |  |   | 107,113   |  
|                                                                               |  |                                           |           |   |      |   |           |      |  |   |           |  
|Total operating expenses                                                       |  |                                           | 2,616,004 |   |      |   | 2,579,200 |      |  |   | 2,357,070 |  
|                                                                               |  |                                           |           |   |      |   |           |      |  |   |           |  
|Operating income                                                               |  |                                           | 338,328   |   |      |   | 332,511   |      |  |   | 333,555   |  
|                                                                               |  |                                           |           |   |      |   |           |      |  |   |           |  
|                                                                               |  |                                           |          
|Other income (deductions):                                                     |  |                                           |           |   |      |   |           |      |  |   |           |  
|Write-down of RCN investment, net                                              |  |                                           |          |   |      |   | (4,450    | )    |  |   | (17,677   | )
|Other income, net                                                              |  |                                           | 7,305     |   |      |   | 14,397    |      |  |   | 22,364    |  
|Other deductions, net                                                          |  |                                           | (1,487    | ) |      |   | (1,712    | )    |  |   | (1,994    | )
|                                                                               |  |                                           |           |   |      |   |           |      |  |   |           |  
|Total other income, net                                                        |  |                                           | 5,818     |   |      |   | 8,235     |      |  |   | 2,693     |  
|                                                                               |  |                                           |           |   |      |   |           |      |  |   |           |  
|                                                                               |  |                                           |          
|Interest charges:                                                              |  |                                           |           |   |      |   |           |      |  |   |           |  
|Long-term debt                                                                 |  |                                           | 119,164   |   |      |   | 121,027   |      |  |   | 115,473   |  
|Transition property securitization                                             |  |                                           | 28,150    |   |      |   | 32,715    |      |  |   | 37,135    |  
|Short-term debt and other                                                      |  |                                           | 7,394     |   |      |   | 8,043     |      |  |   | 22,848    |  
|Allowance for borrowed funds used during construction and capitalized interest |  |                                           | (1,003    | ) |      |   | (4,573    | )    |  |   | (2,875    | )
|                                                                               |  |                                           |           |   |      |   |           |      |  |   |           |  
|Total interest charges                                                         |  |                                           | 153,705   |   |      |   | 157,212   |      |  |   | 172,581   |  
|                                                                               |  |                                           |           |   |      |   |           |      |  |   |           |  
|                                                                               |  |                                           |          
|Preferred stock dividends of subsidiary                                        |  |                                           | 1,960     |   |      |   | 1,960     |      |  |   | 1,960     |  
|                                                                               |  |                                           |           |   |      |   |           |      |  |   |           |  
|Net income                                                                     |  | $                                         | 188,481   |   |      | $ | 181,574   |      |  | $ | 161,707   |  
|                                                                               |  |                                           |           |   |      |   |           |      |  |   |           |  
|Weighted average common shares outstanding:                                    |  |                                           |           |   |      |   |           |      |  |   |           |  
|Basic                                                                          |  |                                           | 53,134    |   |      |   | 53,033    |      |  |   | 53,033    |  
|Diluted                                                                        |  |                                           | 53,646    |   |      |   | 53,399    |      |  |   | 53,297    |  
|                                                                               |  |                                           |          
|Earnings per common share:                                                     |  |                                           |           |   |      |   |           |      |  |   |           |  
|Basic                                                                          |  | $                                         | 3.55      |   |      | $ | 3.42      |      |  | $ | 3.05      |  
|Diluted                                                                        |  | $                                         | 3.51      |   |      | $ | 3.40      |      |  | $ | 3.03      |  



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



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##### Table of Contents

NSTAR

Consolidated Statements of Comprehensive Income



|                                                                   |  |                          |         |   |      |   |         |      |  |   |         |  
|------------------------------------------------------------------ |  | ------------------------ | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                                                   |  | Years ended December 31, |        
|                                                                   |  | 2004                     |         |   | 2003 |   |         | 2002 | 
|                                                                   |  | (in thousands)           |        
|Net income                                                         |  | $                        | 188,481 |   |      | $ | 181,574 |      |  | $ | 161,707 |  
|Other comprehensive income, net:                                   |  |                          |         |   |      |   |         |      |  |   |         |  
|Unrealized gain (loss) on investments                              |  |                          |        |   |      |   | 2,783   |      |  |   | (17,819 | )
|Reclassification adjustment for (gain) loss included in net income |  |                          |        |   |      |   | (2,783  | )    |  |   | 15,110  |  
|Additional minimum pension liability                               |  |                          | (5,817  | ) |      |   | 1,104   |      |  |   | (12,470 | )
|Deferred income taxes (benefit)                                    |  |                          | 2,414   |   |      |   | (389    | )    |  |   | 5,927   |  
|                                                                   |  |                          |         |   |      |   |         |      |  |   |         |  
|Comprehensive income                                               |  | $                        | 185,078 |   |      | $ | 182,289 |      |  | $ | 152,455 |  
|                                                                   |  |                          |         |   |      |   |         |      |  |   |         |  



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



NSTAR

Consolidated Statements of Retained Earnings



|                                     |  |                          |         |      |   |         |  |   |        
|------------------------------------ |  | ------------------------ | ------- | ---- | - | ------- |  | - | -------
|                                     |  | Years ended December 31,
|                                     |  | 2004                     |         | 2003 |   | 2002   
|                                     |  | (in thousands)          
|Balance at the beginning of the year |  | $                        | 449,114 |      | $ | 382,886 |  | $ | 334,138
|Add:                                 |  |                          |         |      |   |         |  |   |        
|Net income                           |  |                          | 188,481 |      |   | 181,574 |  |   | 161,707
|                                     |  |                          |         |      |   |         |  |   |        
|Subtotal                             |  |                          | 637,595 |      |   | 564,460 |  |   | 495,845
|                                     |  |                          |         |      |   |         |  |   |        
|Deduct:                              |  |                          |         |      |   |         |  |   |        
|Dividends declared:                  |  |                          |         |      |   |         |  |   |        
|Common shares                        |  |                          | 119,343 |      |   | 115,346 |  |   | 112,959
|                                     |  |                          |         |      |   |         |  |   |        
|Balance at the end of the year       |  | $                        | 518,252 |      | $ | 449,114 |  | $ | 382,886
|                                     |  |                          |         |      |   |         |  |   |        



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



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NSTAR

Consolidated Balance Sheets



|                                                                                                                                                     |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|---------------------------------------------------------------------------------------------------------------------------------------------------- |  | -------------- | --------- | ---- |  | - | --------- |  | - | --------- | - |  | - | ---------
|                                                                                                                                                     |  | December 31,  
|                                                                                                                                                     |  | (in thousands)
|                                                                                                                                                     |  | 2004           |           | 2003
|Assets                                                                                                                                               |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|Utility plant in service, at original cost                                                                                                           |  | $              | 4,412,073 |      |  |   |           |  | $ | 4,254,848 |   |  |   |          
|Less: accumulated depreciation                                                                                                                       |  |                | 1,090,924 |      |  | $ | 3,321,149 |  |   | 1,109,248 |   |  | $ | 3,145,600
|                                                                                                                                                     |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|Construction work in progress                                                                                                                        |  |                |           |      |  |   | 103,866   |  |   |           |   |  |   | 70,500   
|                                                                                                                                                     |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|Net utility plant                                                                                                                                    |  |                |           |      |  |   | 3,425,015 |  |   |           |   |  |   | 3,216,100
|Non-utility property, net                                                                                                                            |  |                |           |      |  |   | 154,963   |  |   |           |   |  |   | 160,556  
|Goodwill                                                                                                                                             |  |                |           |      |  |   | 426,870   |  |   |           |   |  |   | 439,122  
|Equity investments                                                                                                                                   |  |                |           |      |  |   | 13,887    |  |   |           |   |  |   | 15,322   
|Other investments                                                                                                                                    |  |                |           |      |  |   | 59,096    |  |   |           |   |  |   | 53,566   
|Current assets:                                                                                                                                      |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|Cash and cash equivalents                                                                                                                            |  |                | 12,497    |      |  |   |           |  |   | 16,526    |   |  |   |          
|Restricted cash                                                                                                                                      |  |                | 10,254    |      |  |   |           |  |   | 13,144    |   |  |   |          
|Accounts receivable, net of allowance of $21,804 and $23,424, respectively                                                                           |  |                | 302,194   |      |  |   |           |  |   | 306,815   |   |  |   |          
|Accrued unbilled revenues                                                                                                                            |  |                | 53,752    |      |  |   |           |  |   | 45,559    |   |  |   |          
|Regulatory assets                                                                                                                                    |  |                | 280,078   |      |  |   |           |  |   | 142,182   |   |  |   |          
|Inventory, at average cost                                                                                                                           |  |                | 86,397    |      |  |   |           |  |   | 79,743    |   |  |   |          
|Other                                                                                                                                                |  |                | 32,497    |      |  |   | 777,669   |  |   | 39,172    |   |  |   | 643,141  
|                                                                                                                                                     |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|Deferred debits:                                                                                                                                     |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|Regulatory assets - power contracts                                                                                                                  |  |                |           |      |  |   | 1,269,651 |  |   |           |   |  |   | 782,856  
|Regulatory assets - retiree benefit costs                                                                                                            |  |                |           |      |  |   | 11,897    |  |   |           |   |  |   | 319,425  
|Regulatory assets - other                                                                                                                            |  |                |           |      |  |   | 595,140   |  |   |           |   |  |   | 610,584  
|Prepaid pension                                                                                                                                      |  |                |           |      |  |   | 297,746   |  |   |           |   |  |   |         
|Other                                                                                                                                                |  |                |           |      |  |   | 85,295    |  |   |           |   |  |   | 91,479   
|                                                                                                                                                     |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|Total assets                                                                                                                                         |  |                |           |      |  | $ | 7,117,229 |  |   |           |   |  | $ | 6,332,151
|                                                                                                                                                     |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|Capitalization and Liabilities                                                                                                                       |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|Common equity:                                                                                                                                       |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|Common shares, par value $1 per share, 100,000,000 shares authorized; 53,275,141 shares in 2004 and 53,032,546 shares in 2003 issued and
outstanding |  | $              | 53,275    |      |  |   |           |  | $ | 53,033    |   |  |   |          
|Premium on common shares                                                                                                                             |  |                | 872,729   |      |  |   |           |  |   | 866,221   |   |  |   |          
|Retained earnings                                                                                                                                    |  |                | 518,252   |      |  |   |           |  |   | 449,114   |   |  |   |          
|Accumulated other comprehensive loss                                                                                                                 |  |                | (3,374    | )    |  | $ | 1,440,882 |  |   | (6,776    | ) |  | $ | 1,361,592
|                                                                                                                                                     |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|Cumulative non-mandatory redeemable preferred stock of subsidiary                                                                                    |  |                |           |      |  |   | 43,000    |  |   |           |   |  |   | 43,000   
|Long-term debt                                                                                                                                       |  |                |           |      |  |   | 1,792,654 |  |   |           |   |  |   | 1,602,402
|Transition property securitization                                                                                                                   |  |                |           |      |  |   | 308,748   |  |   |           |   |  |   | 377,150  
|Current liabilities:                                                                                                                                 |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|Long-term debt                                                                                                                                       |  |                | 108,197   |      |  |   |           |  |   | 189,956   |   |  |   |          
|Transition property securitization                                                                                                                   |  |                | 41,048    |      |  |   |           |  |   | 40,077    |   |  |   |          
|Notes payable                                                                                                                                        |  |                | 161,400   |      |  |   |           |  |   | 239,100   |   |  |   |          
|Deferred income taxes                                                                                                                                |  |                | 8,072     |      |  |   |           |  |   | 13,961    |   |  |   |          
|Accounts payable                                                                                                                                     |  |                | 239,613   |      |  |   |           |  |   | 224,987   |   |  |   |          
|Power contracts                                                                                                                                      |  |                | 171,312   |      |  |   |           |  |   | 16,231    |   |  |   |          
|Accrued interest                                                                                                                                     |  |                | 33,073    |      |  |   |           |  |   | 34,490    |   |  |   |          
|Dividends payable                                                                                                                                    |  |                | 31,227    |      |  |   |           |  |   | 29,760    |   |  |   |          
|Accrued expenses                                                                                                                                     |  |                | 93,844    |      |  |   |           |  |   | 95,624    |   |  |   |          
|Other                                                                                                                                                |  |                | 73,346    |      |  |   | 961,132   |  |   | 71,964    |   |  |   | 956,150  
|                                                                                                                                                     |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|Deferred credits:                                                                                                                                    |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|Accumulated deferred income taxes and unamortized investment tax credits                                                                             |  |                |           |      |  |   | 840,461   |  |   |           |   |  |   | 765,507  
|Power contracts                                                                                                                                      |  |                |           |      |  |   | 1,269,651 |  |   |           |   |  |   | 782,856  
|Pension liability                                                                                                                                    |  |                |           |      |  |   | 31,296    |  |   |           |   |  |   | 46,659   
|Regulatory liability - cost of removal                                                                                                               |  |                |           |      |  |   | 258,722   |  |   |           |   |  |   | 223,074  
|Other                                                                                                                                                |  |                |           |      |  |   | 170,683   |  |   |           |   |  |   | 173,761  
|Commitments and contingencies                                                                                                                        |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|                                                                                                                                                     |  |                |           |      |  |   |           |  |   |           |   |  |   |          
|Total capitalization and liabilities                                                                                                                 |  |                |           |      |  | $ | 7,117,229 |  |   |           |   |  | $ | 6,332,151
|                                                                                                                                                     |  |                |           |      |  |   |           |  |   |           |   |  |   |          



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



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NSTAR

Consolidated Statements of Cash Flows



|                                                                                  |  |                          |          |   |      |   |          |      |  |   |          |  
|--------------------------------------------------------------------------------- |  | ------------------------ | -------- | - | ---- | - | -------- | ---- |  | - | -------- | -
|                                                                                  |  | Years ended December 31, |         
|                                                                                  |  | 2004                     |          |   | 2003 |   |          | 2002 | 
|                                                                                  |  | (in thousands)           |         
|Operating activities:                                                             |  |                          |          |   |      |   |          |      |  |   |          |  
|Net income                                                                        |  | $                        | 188,481  |   |      | $ | 181,574  |      |  | $ | 161,707  |  
|Adjustments to reconcile net income to net cash provided by operating activities: |  |                          |          |   |      |   |          |      |  |   |          |  
|Depreciation and amortization                                                     |  |                          | 246,363  |   |      |   | 236,336  |      |  |   | 239,800  |  
|Deferred income taxes                                                             |  |                          | 79,570   |   |      |   | 128,379  |      |  |   | (13,311  | )
|Loss on write-down of RCN investment                                              |  |                          |         |   |      |   | 6,146    |      |  |   | 37,343   |  
|Allowance for borrowed funds used during construction/capitalized interest        |  |                          | (1,003   | ) |      |   | (4,573   | )    |  |   | (2,875   | )
|Power contract buy-out                                                            |  |                          | (5,310   | ) |      |   | (12,741  | )    |  |   | (12,741  | )
|Net changes in:                                                                   |  |                          |          |   |      |   |          |      |  |   |          |  
|Accounts receivable and accrued unbilled revenues                                 |  |                          | (3,572   | ) |      |   | (6,526   | )    |  |   | 166,425  |  
|Inventory, at average cost                                                        |  |                          | (6,812   | ) |      |   | (21,188  | )    |  |   | 9,554    |  
|Other current assets                                                              |  |                          | (128,821 | ) |      |   | (3,531   | )    |  |   | 17,422   |  
|Accounts payable                                                                  |  |                          | 8,014    |   |      |   | 10,536   |      |  |   | 15,869   |  
|Other current liabilities                                                         |  |                          | 147,377  |   |      |   | 1,151    |      |  |   | (105,582 | )
|Deferred debits and credits                                                       |  |                          | (291,562 | ) |      |   | (86,314  | )    |  |   | 68,165   |  
|Net change from other miscellaneous operating activities                          |  |                          | 204,739  |   |      |   | (3,970   | )    |  |   | (13,439  | )
|                                                                                  |  |                          |          |   |      |   |          |      |  |   |          |  
|Net cash provided by operating activities                                         |  |                          | 437,464  |   |      |   | 425,279  |      |  |   | 568,337  |  
|                                                                                  |  |                          |          |   |      |   |          |      |  |   |          |  
|                                                                                  |  |                          |         
|Investing activities:                                                             |  |                          |          |   |      |   |          |      |  |   |          |  
|Plant expenditures (excluding AFUDC/capitalized interest)                         |  |                          | (313,387 | ) |      |   | (307,655 | )    |  |   | (368,084 | )
|Proceeds on sale of property, net                                                 |  |                          | 14,252   |   |      |   | 17,572   |      |  |   | 26,866   |  
|Investments                                                                       |  |                          | (4,095   | ) |      |   | 669      |      |  |   | 9,445    |  
|                                                                                  |  |                          |          |   |      |   |          |      |  |   |          |  
|Net cash used in investing activities                                             |  |                          | (303,230 | ) |      |   | (289,414 | )    |  |   | (331,773 | )
|                                                                                  |  |                          |          |   |      |   |          |      |  |   |          |  
|                                                                                  |  |                          |         
|Financing activities (Note O):                                                    |  |                          |          |   |      |   |          |      |  |   |          |  
|Long-term debt redemptions                                                        |  |                          | (258,357 | ) |      |   | (242,357 | )    |  |   | (166,917 | )
|Debt issue costs                                                                  |  |                          | (1,851   | ) |      |   | (663     | )    |  |   | (5,218   | )
|Issuance of long-term debt                                                        |  |                          | 300,000  |   |      |   | 150,000  |      |  |   | 500,000  |  
|Net change in notes payable                                                       |  |                          | (77,700  | ) |      |   | 40,500   |      |  |   | (426,247 | )
|Change in disbursement accounts                                                   |  |                          | 11,922   |   |      |   | (3,747   | )    |  |   | 17,990   |  
|Common stock issuance                                                             |  |                          | 7,558    |   |      |   |         |      |  |   |         |  
|Dividends paid                                                                    |  |                          | (119,835 | ) |      |   | (116,510 | )    |  |   | (114,389 | )
|                                                                                  |  |                          |          |   |      |   |          |      |  |   |          |  
|Net cash used in financing activities                                             |  |                          | (138,263 | ) |      |   | (172,777 | )    |  |   | (194,781 | )
|                                                                                  |  |                          |          |   |      |   |          |      |  |   |          |  
|Net (decrease) increase in cash and cash equivalents                              |  |                          | (4,029   | ) |      |   | (36,912  | )    |  |   | 41,783   |  
|Cash and cash equivalents at the beginning of the year                            |  |                          | 16,526   |   |      |   | 53,438   |      |  |   | 11,655   |  
|                                                                                  |  |                          |          |   |      |   |          |      |  |   |          |  
|Cash and cash equivalents at the end of the year                                  |  | $                        | 12,497   |   |      | $ | 16,526   |      |  | $ | 53,438   |  
|                                                                                  |  |                          |          |   |      |   |          |      |  |   |          |  
|                                                                                  |  |                          |         
|Supplemental disclosures of cash flow information:                                |  |                          |          |   |      |   |          |      |  |   |          |  
|Cash paid (received) during the year for:                                         |  |                          |          |   |      |   |          |      |  |   |          |  
|Interest, net of amounts capitalized                                              |  | $                        | 144,762  |   |      | $ | 154,956  |      |  | $ | 155,265  |  
|Income taxes (refund)                                                             |  | $                        | 34,627   |   |      | $ | (4,526   | )    |  | $ | 95,980   |  
|Non-cash financing activity:                                                      |  |                          |          |   |      |   |          |      |  |   |          |  
|Non-cash common share issuance                                                    |  | $                        | 4,063    |   |      | $ |         |      |  | $ |         |  



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



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Notes to Consolidated Financial Statements



Note A. Business Organization and Summary of Significant Accounting Policies



1. About NSTAR



NSTAR (or the Company) is a holding company engaged through its subsidiaries in the energy delivery business serving approximately 1.4 million customers in Massachusetts,
including approximately 1.1 million electric distribution customers in 81 communities and approximately 300,000 natural gas distribution customers in 51 communities. NSTAR was created in 1999 in connection with the merger of BEC Energy and
Commonwealth Energy System. 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 collectively operate as NSTAR Electric. Reference in this report to NSTAR shall mean the registrant NSTAR or NSTAR
and its subsidiaries as the context requires. Reference in this report to NSTAR Electric shall mean Boston Edison, ComElectric and Cambridge Electric together. NSTARs non-utility, unregulated operations include district energy
operations (Advanced Energy Systems, Inc. and NSTAR Steam Corporation), telecommunications operations (NSTAR Communications, Inc. (NSTAR Com)) and a liquefied natural gas service company (Hopkinton LNG Corp.).



2. Basis of Consolidation and Accounting



The accompanying Consolidated Financial Statements reflect the results of operations,
comprehensive income, retained earnings, financial position and cash flows of NSTAR and its subsidiaries. All significant intercompany transactions have been eliminated in consolidation. Certain immaterial reclassifications have been made to prior
year amounts to conform to the current years presentation.



NSTARs
utility subsidiaries follow accounting policies prescribed by the Federal Energy Regulatory Commission (FERC) and the Massachusetts Department of Telecommunications and Energy (MDTE). In addition, NSTAR and its subsidiaries are subject to the
accounting and reporting requirements of the Securities and Exchange Commission (SEC). The accompanying Consolidated Financial Statements conform to accounting principles generally accepted in the United States of America (GAAP). The utility
subsidiaries are subject to the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71). The application of SFAS 71
results in differences in the timing of recognition of certain expenses from those of other businesses and industries. The distribution and transmission businesses remain subject to rate-regulation and continue to meet the criteria for application
of SFAS 71. Refer to Note D to these Consolidated Financial Statements for more information on regulatory assets.



The preparation of financial statements in conformity with GAAP requires management of NSTAR and its subsidiaries to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from
these estimates.



3. Revenues



Utility revenues are based on authorized rates approved by the MDTE and FERC. Estimates of
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.



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4. Utility Plant



Utility plant is stated at original cost. The cost 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, is charged to accumulated depreciation. The incurred related cost of removal is charged against the Regulatory liability - cost of
removal.



5. Non-Utility Plant



Non-utility property is stated at cost or its net realizable value. The following is a
summary of non-utility property and equipment, at cost less accumulated depreciation, at December 31:



|                               |  |      |         |   |      |   |         |  
|------------------------------ |  | ---- | ------- | - | ---- | - | ------- | -
|(in thousands)                 |  | 2004 |         |   | 2003 |  
|Land                           |  | $    | 15,700  |   |      | $ | 15,604  |  
|Energy production equipment    |  |      | 136,929 |   |      |   | 132,487 |  
|Telecommunications equipment   |  |      | 39,287  |   |      |   | 38,314  |  
|Gas storage                    |  |      | 42,701  |   |      |   | 42,701  |  
|Buildings and improvements     |  |      | 2,992   |   |      |   | 2,992   |  
|                               |  |      |         |   |      |   |         |  
|                               |  |      | 237,609 |   |      |   | 232,098 |  
|Less: accumulated depreciation |  |      | (83,104 | ) |      |   | (72,123 | )
|                               |  |      |         |   |      |   |         |  
|                               |  |      | 154,505 |   |      |   | 159,975 |  
|Construction work in progress  |  |      | 458     |   |      |   | 581     |  
|                               |  |      |         |   |      |   |         |  
|                               |  | $    | 154,963 |   |      | $ | 160,556 |  
|                               |  |      |         |   |      |   |         |  



6.
Depreciation



Depreciation of utility plant is computed on a straight-line
basis using composite rates based on the estimated useful lives of the various classes of property. The composite rates are subject to the approval of the MDTE and FERC. The overall composite depreciation rates for utility property were 3.02%, 3.04%
and 3.26% in 2004, 2003 and 2002, respectively. The rates include a cost of removal component, which is collected from customers.



Depreciation of non-utility property is computed on a straight-line basis over the estimated life of the asset. The estimated depreciable service lives (in years) of the
major components of non-utility property and equipment are as follows:



|                                 |  |                
|-------------------------------- |  | ---------------
|Plant Component                  |  | DepreciableLife
|Energy production equipment      |  | 25-35          
|Telecommunications equipment     |  | 10             
|Liquefied gas storage facilities |  | 28             
|Buildings and improvements       |  | 40             



Depreciation expense on non-utility
property and equipment was $13 million, $12 million and $9 million for 2004, 2003 and 2002, respectively.



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 and amortized as an addition to interest expense over the life of the original or replacement debt. 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.



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



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 2004, 2003 and 2002 were 1.72%, 1.60% and 2.26%, respectively, and represented only the costs of short-term debt.



NSTAR capitalizes interest costs on long-term construction projects related to
its unregulated businesses. Interest costs of $3.7 million during 2003 were capitalized for the construction of new combustion turbines at AES MATEP facility. No interest costs were capitalized during 2004.



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 remainder of 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, funds held by a trustee in connection with Advanced Energy Systems 6.924% Note Agreement, and funds held in reserve for a trust on behalf of Boston Edison to pay the principal and interest on the transition property
securitization.



NSTARs banking arrangements provide for daily cash
transfers to our disbursement accounts as vendor checks are presented for payment. The balances of the disbursement accounts amount to $26,165 and $14,243 at December 31, 2004 and 2003, respectively, and are included in accounts payable on the
accompanying Consolidated Balance Sheets. Changes in the balances of the disbursement accounts are reflected in financing activities in the accompanying Statement of Cash Flows.



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 4% to 14% in three regional nuclear facilities that are currently being decommissioned.



11. Goodwill and Costs to Achieve



The merger that created NSTAR was accounted for using the purchase method of accounting. The premium (Goodwill) associated with the acquisition was approximately $490
million, while the original estimate of transaction and integration costs to achieve the merger was $111 million. The merger premium is reflected on the accompanying Consolidated Balance Sheets as Goodwill. In accordance with the MDTEs order,
this premium is being amortized over 40 years at an annual rate of $12.2 million, while the costs to achieve (CTA) are being amortized over 10 years. CTA are the costs incurred to execute the merger including the costs of a voluntary severance
program, costs of financial advisors, legal costs, and other transaction and systems integration costs. CTA was being amortized at an annual rate of $11.1 million through the rate freeze period based on the original rate plan, as approved by the
MDTE. Effective upon completion of the four-year rate freeze on August 25, 2003, the amortization expense was increased to reflect the actual CTA expenditures incurred. As a result, the total CTA amortization expense for 2004 and 2003 was
approximately $16.4 million and $12.9 million, respectively. In 2003, NSTAR, as mandated by the MDTE, filed a Revised Savings Report which detailed the actual realized savings as a result of the merger that created NSTAR. The filing included an
update on the actual CTA costs



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incurred. This report included a final accounting of the deductibility for income tax purposes of each component of CTA. In 2004, the MDTE determined that no
further action was required on the Revised Savings Report. The total CTA is approximately $143 million. This increase from the original estimate is partially mitigated by the fact that the portion of CTA that is not deductible for income tax
purposes is approximately $20 million lower than the original estimate. NSTAR anticipates that these incremental costs are probable of recovery in future rates. The CTA and Goodwill amounts were filed and approved as part of the rate plan.



12. Stock Option Plan



NSTARs 1997 Share Incentive Plan is a stock-based employee compensation plan and is
described more fully in the accompanying Note J to Consolidated Financial Statements. NSTAR applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB
25) and related Interpretations in accounting for this plan. Currently, no stock-based employee compensation expense for option grants is reflected in net income, as all options granted under this plan had an exercise price equal to the market value
of the underlying common shares on the date of grant. The following table illustrates the effect on net income and earnings per common share if NSTAR had applied the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based
Compensation to stock-based employee compensation.



|                                                                                                                                              |  |                          |         |   |      |   |         |      |  |   |         |  
|--------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------ | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|(in thousands, except earnings per common share amounts)                                                                                      |  |                          |        
|                                                                                                                                              |  | Years ended December 31, |        
|                                                                                                                                              |  | 2004                     |         |   | 2003 |   |         | 2002 | 
|Net income                                                                                                                                    |  | $                        | 188,481 |   |      | $ | 181,574 |      |  | $ | 161,707 |  
|Add: Share grant incentive compensation expense included in reported net income, net of related tax effects                                   |  |                          | 2,608   |   |      |   | 2,147   |      |  |   | 1,642   |  
|Deduct: Total share grant and stock option compensation expense determined under fair value method for all awards, net of related tax
effects |  |                          | (3,385  | ) |      |   | (2,870  | )    |  |   | (2,489  | )
|                                                                                                                                              |  |                          |         |   |      |   |         |      |  |   |         |  
|Pro forma net income                                                                                                                          |  | $                        | 187,704 |   |      | $ | 180,851 |      |  | $ | 160,860 |  
|                                                                                                                                              |  |                          |         |   |      |   |         |      |  |   |         |  
|Earnings per common share:                                                                                                                    |  |                          |         |   |      |   |         |      |  |   |         |  
|Basic - as reported                                                                                                                           |  | $                        | 3.55    |   |      | $ | 3.42    |      |  | $ | 3.05    |  
|Basic - pro forma                                                                                                                             |  | $                        | 3.53    |   |      | $ | 3.41    |      |  | $ | 3.03    |  
|Diluted - as reported                                                                                                                         |  | $                        | 3.51    |   |      | $ | 3.40    |      |  | $ | 3.03    |  
|Diluted - pro forma                                                                                                                           |  | $                        | 3.50    |   |      | $ | 3.39    |      |  | $ | 3.02    |  



13.
Other Income (Deductions), net



Major components of other income, net were as
follows:



|                                                                     |  |                          |       |   |      |   |        |      |  |   |        |  
|-------------------------------------------------------------------- |  | ------------------------ | ----- | - | ---- | - | ------ | ---- |  | - | ------ | -
|                                                                     |  | Years ended December 31, |      
|(in thousands)                                                       |  | 2004                     |       |   | 2003 |   |        | 2002 | 
|Equity earnings, dividends and other investment income               |  | $                        | 1,607 |   |      | $ | 2,205  |      |  | $ | 2,667  |  
|Interest and rental income                                           |  |                          | 4,859 |   |      |   | 3,244  |      |  |   | 5,025  |  
|Sale of Blackstone Station                                           |  |                          | 1,700 |   |      |   | 1,386  |      |  |   |       |  
|Tax valuation allowance adjustment                                   |  |                          |      |   |      |   | 8,485  |      |  |   | 3,849  |  
|Gain on demutualized securities                                      |  |                          |      |   |      |   |       |      |  |   | 4,928  |  
|Investment tax credit                                                |  |                          |      |   |      |   |       |      |  |   | 7,272  |  
|Miscellaneous other income, (includes applicable income tax expense) |  |                          | (861  | ) |      |   | (923   | )    |  |   | (1,377 | )
|                                                                     |  |                          |       |   |      |   |        |      |  |   |        |  
|                                                                     |  | $                        | 7,305 |   |      | $ | 14,397 |      |  | $ | 22,364 |  
|                                                                     |  |                          |       |   |      |   |        |      |  |   |        |  



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Major components of other deductions, net were as follows:



|                                                                                   |  |                          |        |   |      |   |        |      |  |   |        |  
|---------------------------------------------------------------------------------- |  | ------------------------ | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|                                                                                   |  | Years ended December 31, |       
|(in thousands)                                                                     |  | 2004                     |        |   | 2003 |   |        | 2002 | 
|Charitable contributions                                                           |  | $                        | (2,654 | ) |      | $ | (1,268 | )    |  | $ | (1,175 | )
|Shutdown costs of unregulated business                                             |  |                          |       |   |      |   |       |      |  |   | (2,000 | )
|Miscellaneous other deductions, (includes applicable income tax benefit (expense)) |  |                          | 1,167  |   |      |   | (444   | )    |  |   | 1,181  |  
|                                                                                   |  |                          |        |   |      |   |        |      |  |   |        |  
|                                                                                   |  | $                        | (1,487 | ) |      | $ | (1,712 | )    |  | $ | (1,994 | )
|                                                                                   |  |                          |        |   |      |   |        |      |  |   |        |  



14.
New Accounting Standards



In December 2004, the FASB issued SFAS No. 123R,
Share-Based Payment. This Standard addresses the accounting for transactions in which a company receives employee services in exchange for (a) equity instruments of the company or (b) liabilities that are based on the fair value of the
companys equity instruments or that may be settled by the issuance of such equity instruments. This Standard eliminates the ability to account for share-based compensation transactions using Accounting Principles Board Opinion No. 25,
Accounting for Stock Issued to Employees, and requires that such transactions be accounted for using a fair-value-based method. The Standard is effective for periods beginning after June 15, 2005. NSTAR is currently assessing the
valuation options allowed in this Standard but, preliminarily, expects this Standard to impact annual earnings by approximately $1.5 million pre-tax, or $0.02 per share.



15. Purchases and Sales Transactions with Independent System Operator - New England (ISO-NE)



As part of NSTAR Electrics normal business operations in order to meet its energy
obligation to its standard offer customers, NSTAR Electric entered into hourly transactions to purchase or sell energy supply to its ISO-NE. The NSTAR Electric transactions with the ISO-NE have been treated as the ISO-NE servicing the incremental
needs of NSTAR Electric, that is, transactions with ISO-NE associated with the difference between NSTAR Electrics resource needs compared to NSTAR Electrics resource availability. NSTAR Electric records the net effect of transactions
with the ISO-NE as an adjustment to purchased power expense.



During 2004 and
2003, NSTAR Electric entered into an agreement whereby all of its energy supply resource entitlements are transferred to an independent energy supplier, following which NSTAR Electric repurchases its energy resource needs from this independent
energy supplier for NSTAR Electrics ultimate sale to its standard offer customers. This transaction has been and will continue to be recorded as a net purchase of electricity.



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 are increased to include the number of
potential dilutive common shares. Diluted EPS reflects the impact on shares outstanding of the deferred (nonvested) shares and stock options granted under the NSTAR Share Incentive Plan.



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The following table summarizes the reconciling amounts between basic and diluted EPS:



|                                                           |  |      |         |      |   |         |  |   |        
|---------------------------------------------------------- |  | ---- | ------- | ---- | - | ------- |  | - | -------
|(in thousands, except per share amounts)                   |  | 2004 |         | 2003 |   | 2002   
|Net income                                                 |  | $    | 188,481 |      | $ | 181,574 |  | $ | 161,707
|Basic EPS                                                  |  | $    | 3.55    |      | $ | 3.42    |  | $ | 3.05   
|Diluted EPS                                                |  | $    | 3.51    |      | $ | 3.40    |  | $ | 3.03   
|Weighted average common shares outstanding for basic EPS   |  |      | 53,134  |      |   | 53,033  |  |   | 53,033 
|Effect of dilutive shares:                                 |  |      |         |      |   |         |  |   |        
|Weighted average dilutive potential common shares          |  |      | 512     |      |   | 366     |  |   | 264    
|                                                           |  |      |         |      |   |         |  |   |        
|Weighted average common shares outstanding for diluted EPS |  |      | 53,646  |      |   | 53,399  |  |   | 53,297 
|                                                           |  |      |         |      |   |         |  |   |        



Note C. Asset Retirement
Obligations



On January 1, 2003, NSTAR adopted SFAS No. 143,
Accounting for Asset Retirement Obligations (SFAS 143). SFAS 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It
applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset, except for certain obligations under lease arrangements.
SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount
of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the
obligation for its recorded amount or incurs a gain or loss upon settlement.



NSTAR has identified certain immaterial long-lived assets, including obligations under lease and easement arrangements, and has determined that it is legally responsible to remove such property.



For its regulated utility businesses, NSTAR has identified legal retirement obligations that
are currently not material to its financial statements. The recognition of a potential asset retirement obligation will have no impact on its earnings. In accordance with SFAS 71, for NSTARs rate-regulated utilities, NSTAR would establish
regulatory assets or liabilities to defer any differences between the liabilities established for ratemaking purposes and those recorded as required under SFAS 143.



For NSTARs regulated utility businesses, the ultimate cost to remove utility plant from service (cost of removal) is recognized as a
component of depreciation expense in accordance with approved regulatory treatment. As of December 31, 2004 and 2003, the estimated amount of the cost of removal included in regulatory liabilities was approximately $259 million and $223 million,
respectively, based on the estimated cost of removal component in current depreciation rates.



NSTAR has identified several long-lived assets, in which it has legal obligations to remove such property, for its non-regulated businesses. As a result, in 2003, NSTAR recorded an increase in non-utility plant of
approximately $0.6 million, an asset retirement liability of approximately $1 million and a cumulative effect of adoption after tax, reducing net income by $0.4 million in 2003. The cumulative effect adjustment was recorded as part of 2003
Depreciation and amortization expense on the accompanying Consolidated Statements of Income.



During 2004, the FASB issued an exposure draft, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. The interpretation clarifies when an entity would be
required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liabilitys fair value can be reasonably estimated. Uncertainty surrounding the timing and method of settlement
that may be conditional on events occurring in the future would be factored into the measurement of the liability



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rather than the recognition of the liability. The interpretation would be effective for NSTAR no later than the end of fiscal year 2005. NSTAR is currently
assessing the impact that the interpretation will have on its consolidated financial position, results of operation and cash flows.



Note D. Regulatory Assets



Regulatory assets represent costs incurred that are expected to be collected from customers through future rates in accordance with agreements with regulators. These
costs are expensed when the corresponding revenues are received in order to appropriately match revenues and expenses.



Regulatory assets consisted of the following:



|                                              |  |              |           |      |   |          
|--------------------------------------------- |  | ------------ | --------- | ---- | - | ---------
|                                              |  | December 31,
|(in thousands)                                |  | 2004         |           | 2003
|Power contracts (including Yankee units)      |  | $            | 1,440,963 |      | $ | 799,087  
|Retiree benefit costs                         |  |              | 34,558    |      |   | 340,111  
|Regulatory assets - other:                    |  |              |           |      |   |          
|Generation-related plant, net                 |  |              | 520,481   |      |   | 504,594  
|Merger costs to achieve                       |  |              | 76,680    |      |   | 93,112   
|Income taxes, net                             |  |              | 50,292    |      |   | 50,161   
|Purchased power costs                         |  |              |          |      |   | 31,969   
|Redemption premiums                           |  |              | 16,785    |      |   | 12,340   
|Other                                         |  |              | 17,007    |      |   | 23,673   
|                                              |  |              |           |      |   |          
|Total current and long-term regulatory assets |  | $            | 2,156,766 |      | $ | 1,855,047
|                                              |  |              |           |      |   |          



Under the traditional revenue
requirements model, electric and gas rates are based on the cost of providing energy delivery service. Under this model, NSTAR Electric and NSTAR Gas are subject to certain accounting standards that are not applicable to other businesses and
industries in general. The application of SFAS 71 requires companies to defer the recognition of certain costs when incurred if future rate recovery of these costs is expected. This is applicable to NSTARs electric and gas distribution and
transmission operations.



Power contracts



The unamortized balance of the estimated costs to decommission the Connecticut Yankee (CY),
Yankee Atomic (YA) and Maine Yankee (MY) nuclear power plants was $116.6 million at December 31, 2004. NSTARs liability for CY decommissioning and its recovery ends in 2010, for YA in 2010 and for MY in 2010. However, should the actual costs
exceed current estimates and anticipated decommissioning dates, NSTAR could have an obligation beyond these periods that would be fully recoverable. These costs are recovered through NSTAR Electrics transition charge. Refer to Note Q,
Commitments and Contingencies, for more discussion.



In
addition, at December 31, 2004 and 2003, $472.3 million and $665.8 million, respectively, represents the recognition of four purchase power contracts at December 31, 2004 and six purchase power contracts at December 31, 2003 as derivatives and their
above-market value and future recovery through NSTAR Electrics transition charges. Refer to Note F, Derivative Instruments - Power Contracts for further details.



The remaining balance at December 31, 2004 of $852.1 million represents the recognition of eight purchase power contract buy-out agreements
that NSTAR Electric executed in 2004 and their future recovery through NSTAR Electrics transition charges. Refer to Note O, Contracts for the Purchase of Energy for further details.



Retiree benefit costs



The retiree benefit regulatory asset of $34.6 million is comprised of $17.4 million of
carrying charges related to a 2003 MDTE order, which will be recovered from customers in 2005, and, $12.8 million of pension and other postretirement benefit obligations other than pension (PBOP) costs deferred under the MDTE order in 2003 and



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2004. Deferred pension and PBOP costs are amortized and collected from customers over three years. The remaining balance of $4.4 million relates to other
pension and PBOP costs deferred in accordance with MDTE directives. These costs are being amortized over periods ranging from two to nine years. Refer to Note I of these Consolidated Financial Statements for further discussion on the MDTE
order.



In 2003, the retiree benefit regulatory asset also included
approximately $299.3 million, which represented the additional minimum pension liability charge required under SFAS 87. As of December 31, 2004, NSTARs Pension Plan did not incur an additional minimum pension liability. As a result, the
liability was reversed. Refer to Note H, Pension and Other Postretirement Benefits for further details.



Generation-related plant



Plant and other regulatory assets related to the divestiture of NSTARs generation business are recovered with a return through the transition charge. This recovery
occurs through 2019 for Boston Edison and through 2023 for ComElectric. This schedule is subject to adjustment by the MDTE.



As of December 31, 2004, $357.2 million of these generation-related regulatory assets are collateralized with the Transition Property Securitization Certificates held by
Boston Edisons subsidiary, BEC Funding LLC. The certificates are non-recourse to Boston Edison.



Merger costs to achieve



An integral part of the merger was the MDTE-approved rate plan of the retail utility subsidiaries of NSTAR. Significant elements of the rate plan include a four-year
distribution rate freeze, recovery of the acquisition premium (goodwill) over 40 years and recovery of transaction and integration costs (costs to achieve) over 10 years. Costs to achieve were the costs incurred to execute the merger including costs
for a voluntary severance program, costs of financial advisors, legal costs and other transaction and systems integration costs. These costs are collected from all NSTAR Electric and NSTAR Gas distribution customers and exclude a return component.
The amortization of these costs have been adjusted since the original recovery began to reflect the actual costs incurred. Refer to Note A to these Consolidated Financial Statements for more information on merger costs to achieve.



Income taxes, net



The principal holder of this regulatory asset is Boston Edison. Approximately $29 million of
this regulatory asset balance reflects deferred tax reserve deficiencies that are being recovered from customers over a 17-year period. In addition, approximately $37 million in additional Boston Edison deferred tax reserve deficiencies have been
recorded in accordance with an MDTE-approved settlement agreement. Offsetting these amounts is approximately $16 million of a regulatory liability associated with unamortized investment tax credits relating to NSTAR Electric and NSTAR Gas.



Purchased power costs



The purchased power costs relate to deferred standard offer service and deferred default
service costs. Customers have the option of continuing to buy power from the retail electric distribution businesses at standard offer prices through February 2005. Since 1998, NSTAR has been allowed to defer the difference between the standard
offer and default service revenues and the cost to supply the power, plus carrying costs. Default service is the electricity that is supplied by the local distribution company when a customer is not receiving power from standard offer service and
has not chosen to receive service from a competitive supplier. The market price for standard offer and default service may fluctuate based on the average market price for power. Amounts collected through standard offer and default service are
recovered on a fully reconciling basis.



Redemption premiums



These amounts reflect the unamortized balance of redemption premiums on
Boston Edison Debentures that are amortized and recovered over the life of the respective debentures pursuant to MDTE approval. There is no return recognized on this balance.



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Other



These amounts primarily consist of deferred transmission costs that are set to be recovered over a subsequent twelve-month period. The deferred costs represent the
difference between the level of billed transmission revenues and the current period costs incurred to provide transmission-related services.



Also, included are environmental costs and response costs that represent the recovery of costs to clean up former gas manufacturing sites over a 7-year period without a
return.



Note E. Derivative Instruments - Power Contracts



NSTAR accounts for its power contracts in accordance with SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities (SFAS 133) and DIG interpretations. NSTAR, at December 31, 2004, recorded four contracts at fair value on its Consolidated Balance Sheets. At December 31, 2003, NSTAR recorded six purchase power
contracts at fair value. Two of the six contracts were divested in 2004 through regulatory-approved buy-out agreements. Refer to Note O of these Consolidated Financial Statements for more detail on the purchase power contract
buy-outs/restructurings. As a result, the recognition of a liability for the fair value of the above-market portion of the remaining four contracts at December 31, 2004 and for the fair value of the above-market portion of the six contracts at
December 31, 2003 is approximately $472 million and $666 million and is a component of Deferred credits - Power contracts on the accompanying Consolidated Balance Sheets. NSTAR has recorded a corresponding regulatory asset to reflect the future
recovery of the above-market component of these contracts through its electric distribution companies transition charge. Therefore, as a result of this regulatory treatment, the recording of these contracts on the accompanying Consolidated
Balance Sheets does not result in an earnings impact.



During the first quarter
of 2005, NSTAR expects to close on a securitization financing that will affect these four contracts that are classified as derivative instruments. NSTAR Electric has entered into buy-out agreements for all four contracts and expects to finance the
buy-out payments through a securitization financing. When this occurs, the fair value of these four contracts will be removed as a derivative instrument from the balance sheet and the securitization debt obligation will be recorded along with an
offsetting regulatory asset.



NSTAR has other purchase power contracts in which
the contract value is significantly above-market. However, these contracts have met the criteria for the normal purchases and sales exception pursuant to SFAS 133 and DIG interpretations and have not been recorded on the accompanying Consolidated
Balance Sheets. The above-market portion of these contracts is currently being recovered through the electric distribution companies transition charge. Therefore, NSTAR does not account for these types of capacity and energy contracts, gas
supply contracts, or purchase orders for numerous supply arrangements as derivatives.



Note F. Variable Interest Entities



In January 2003, the FASB
issued Interpretation No. 46, Consolidation of Variable Interest Entities, as revised in December 2003 (FIN 46R), which addresses the consolidation of variable interest entities (VIE) by business enterprises that are the primary
beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling
financial interest. The primary beneficiary of a VIE is the enterprise with the majority of the risks or rewards associated with the VIE. This interpretation had two effective dates: December 31, 2003 and March 31, 2004.



NSTAR has a wholly owned special purpose subsidiary, BEC Funding LLC, established to
undertake the sale of $725 million in notes to a special purpose trust created by two Massachusetts state agencies. NSTAR consolidates this entity. As part of NSTARs assessment of FIN 46R and, for compliance at December 31, 2003, NSTAR
reviewed the substance of this entity to determine if it is still proper to consolidate this entity. Based on its review, NSTAR has concluded that BEC Funding LLC is a VIE and should continue to be consolidated by NSTAR.



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For the March 31, 2004 effective date of FIN 46R, NSTAR evaluated other entities with which it conducts significant
transactions, including companies that supply power to NSTAR Electric through its purchase power agreements. NSTAR determined that it is possible that five of these companies may be considered VIEs. These companies have power plants that have daily
capacity output ranging from 20 megawatts (MW) to 330 MW. Through December 31, 2004 and 2003, NSTAR Electric purchased a total of approximately 4,001 megawatt-hours (MWH) and 4,487 MWH, respectively, under these agreements. These purchases
approximate 17% of the total MWH purchased by NSTAR Electric for the years ended December 31, 2004 and 2003 and amounted to approximately $381 million and $386 million, respectively. In order to determine if these counterparties are VIEs and if
NSTAR Electric is the primary beneficiary of these counterparties, NSTAR Electric concluded that it needed more information from the entities. NSTAR Electric attempted to obtain the information required and requested, in writing, these entities
provide the Company with the necessary information. However, each of the entities has indicated that they will not provide the requested information as they are not contractually obligated to provide such confidential information. Since NSTAR
Electric was unable to obtain the necessary information and, as allowed under a scope exception in FIN 46R, the accompanying Consolidated Financial Statements do not reflect the consolidation of any entities with which NSTAR Electric has a purchase
power agreement.



Additionally, during 2004, NSTAR Electric executed purchase
power buy-out/restructuring agreements with a majority of the entities from which NSTAR Electric attempted to obtain additional information in order to determine if these entities are VIEs. These buy-out/restructurings agreements received regulatory
approval in January 2005. Refer to Note O for more detail on the purchase power agreements. As a result, NSTAR will no longer pursue obtaining the necessary information to determine whether it has a variable interest in these entities.



Note G. 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 71
and SFAS 109, net regulatory assets of $50.3 million and $50.2 million and corresponding net increases in accumulated deferred income taxes were recorded as of December 31, 2004 and 2003, respectively. The regulatory assets represent the additional
future revenues to be collected from customers for deferred income taxes.



Accumulated deferred income taxes and unamortized investment tax credits consisted of the following:



|                                               |  |              |         |      |   |        
|---------------------------------------------- |  | ------------ | ------- | ---- | - | -------
|                                               |  | December 31,
|(in thousands)                                 |  | 2004         |         | 2003
|Deferred tax liabilities:                      |  |              |         |      |   |        
|Plant-related                                  |  | $            | 555,095 |      | $ | 495,617
|Transition costs                               |  |              | 151,015 |      |   | 178,840
|Other                                          |  |              | 263,783 |      |   | 239,531
|                                               |  |              |         |      |   |        
|                                               |  |              | 969,893 |      |   | 913,988
|                                               |  |              |         |      |   |        
|Deferred tax assets:                           |  |              |         |      |   |        
|Plant-related                                  |  |              | 50,864  |      |   | 55,503 
|Investment tax credits                         |  |              | 16,101  |      |   | 17,190 
|Other                                          |  |              | 79,588  |      |   | 88,736 
|                                               |  |              |         |      |   |        
|                                               |  |              | 146,553 |      |   | 161,429
|                                               |  |              |         |      |   |        
|Net accumulated deferred income taxes          |  |              | 823,340 |      |   | 752,559
|Accumulated unamortized investment tax credits |  |              | 25,193  |      |   | 26,909 
|                                               |  |              |         |      |   |        
|                                               |  | $            | 848,533 |      | $ | 779,468
|                                               |  |              |         |      |   |        



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Previously deferred investment tax credits are amortized over the estimated remaining lives of the property which
generated the credits.



Components of income tax expense were as follows:



|                                                  |  |      |         |   |      |   |         |      |  |   |         |  
|------------------------------------------------- |  | ---- | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|(in thousands)                                    |  | 2004 |         |   | 2003 |   |         | 2002 | 
|Current income tax expense                        |  | $    | 36,668  |   |      | $ | 39,188  |      |  | $ | 89,201  |  
|Deferred income tax expense                       |  |      | 81,286  |   |      |   | 83,944  |      |  |   | 19,886  |  
|Investment tax credit amortization                |  |      | (1,716  | ) |      |   | (1,723  | )    |  |   | (1,974  | )
|                                                  |  |      |         |   |      |   |         |      |  |   |         |  
|Income taxes charged to operations                |  |      | 116,238 |   |      |   | 121,409 |      |  |   | 107,113 |  
|                                                  |  |      |         |   |      |   |         |      |  |   |         |  
|Tax expense (benefit) on other income net:        |  |      |         |   |      |   |         |      |  |   |         |  
|Current income tax expense (benefit)              |  |      | 2,989   |   |      |   | (54,668 | )    |  |   | 5,352   |  
|Deferred income tax expense (benefit)             |  |      |        |   |      |   | 46,157  |      |  |   | (30,789 | )
|                                                  |  |      |         |   |      |   |         |      |  |   |         |  
|Income tax expense (benefit) on other income, net |  |      | 2,989   |   |      |   | (8,511  | )    |  |   | (25,437 | )
|                                                  |  |      |         |   |      |   |         |      |  |   |         |  
|Total income tax expense                          |  | $    | 119,227 |   |      | $ | 112,898 |      |  | $ | 81,676  |  
|                                                  |  |      |         |   |      |   |         |      |  |   |         |  



In 2002, tax expense on other income,
net reflects $7.3 million of investment tax credits recognized as a result of the sale of NSTARs equity interest in the Seabrook generating unit.



The effective income tax rates reflected in the accompanying consolidated financial statements and the reasons for their differences from the statutory federal income tax
rate were as follows:



|                                                                                           |  |      |   |  |      |   |  |      |  
|------------------------------------------------------------------------------------------ |  | ---- | - |  | ---- | - |  | ---- | -
|                                                                                           |  | 2004 |   |  | 2003 |   |  | 2002 |  
|Statutory tax rate                                                                         |  | 35.0 | % |  | 35.0 | % |  | 35.0 | %
|State income tax, net of federal income tax benefit                                        |  | 3.9  |   |  | 5.3  |   |  | 4.8  |  
|Investment tax credits                                                                     |  | (0.6 | ) |  | (0.6 | ) |  | (3.2 | )
|Other                                                                                      |  | 0.4  |   |  | 1.4  |   |  | 1.0  |  
|                                                                                           |  |      |   |  |      |   |  |      |  
|Effective tax rate before write-down and tax valuation allowance adjustment                |  | 38.7 |   |  | 41.1 |   |  | 37.6 |  
|Adjustment to tax valuation allowance and write-down of RCN investment (federal and state) |  |     |   |  | (2.8 | ) |  | (4.0 | )
|                                                                                           |  |      |   |  |      |   |  |      |  
|Effective tax rate                                                                         |  | 38.7 | % |  | 38.3 | % |  | 33.6 | %
|                                                                                           |  |      |   |  |      |   |  |      |  



Income Tax Matters



a. RCN Abandonment Tax Treatment



As a result of the RCN share abandonment, the Company claimed an ordinary loss on its 2003
tax return for this item. The ordinary loss tax treatment resulted in the Company realizing the benefits represented by the tax asset recorded on its books that resulted from the previous write-down of this asset for financial reporting purposes.
The requirement for a tax valuation allowance, therefore, is no longer applicable. Accordingly, the Company reversed this reserve as of December 31, 2003.



The Company believes it is more likely than not that it is entitled to this ordinary loss deduction. The Company expects the Internal Revenue Service (IRS) to review this
transaction and it is possible that the IRS will disagree. In accordance with the Companys tax policy as it relates to uncertain tax positions, the Company has established a loss contingency of approximately $44 million at December 31, 2003.
This amount represents the tax impact to the Company should the ordinary loss ultimately be recharacterized to a capital loss. This contingent liability is recorded as part of Deferred credits - Other on the accompanying Consolidated Balance Sheets.



If the Companys position is not upheld, the Company may be required to
make future cash expenditures to the IRS that may impact NSTARs cash requirements in future periods.



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b. Tax Valuation Allowance



SFAS 109 prohibits the recognition of all or a portion of deferred income tax benefits if it is more likely than not that the deferred tax
asset will not be realized. NSTAR had determined that it was more likely than not that a current or future income tax benefit would not be realized relating to the write-downs of its RCN investment that were recorded in the second and fourth
quarters of 2002 and previously in the first quarter of 2001. These write-downs resulted from the significant declines in the market value of the telecommunications sector, including RCN. As a result of this uncertainty, NSTAR recorded a $77.6
million tax valuation allowance on the entire tax benefit associated with these write-downs during 2001 and 2002. During 2003 and 2002, as a result of previously unanticipated capital gain transactions, NSTAR recognized $8.5 million and $3.9
million, respectively, of this tax benefit.



Additionally, based on the IRS
review of NSTARs 1999 and 2000 federal income tax returns, NSTAR recognized the tax benefits relating to the incremental operating losses from the joint venture that were allocated to NSTAR. These tax returns are currently at the Office of IRS
Appeals on other matters. The tax valuation allowance included reserves related to the tax treatment of these losses through June 19, 2002, the final date of joint venture loss allocation to NSTAR. Each of the tax returns filed for 1999 through 2001
claimed operating losses. The tax return filed for 2002 claimed the remaining portion of these operating losses. Based on the IRS examining agents review, no adjustment for the years under audit was proposed. This determination was arrived at
in the fourth quarter of 2002 and, as a result, NSTAR applied the treatment of these operating losses for all years on a consistent basis, allowing a reduction to its valuation allowance of approximately $19.7 million as a reduction to income tax
expense included as a component of the write-down of the RCN investment.



On
December 24, 2003, NSTAR exited from its investment in RCN and formally abandoned the 11.6 million shares of RCN common stock. As mentioned above, a tax valuation allowance had been established in a previous year to offset the potential future tax
benefits resulting from write-downs of NSTARs investment in RCN. As a result of the abandonment, the Company claimed an ordinary loss on its 2003 tax return. This treatment results in the Company realizing the benefits represented by the tax
asset recorded on its books that resulted from the previous write-downs of this investment for financial reporting purposes. The requirement for a tax valuation allowance, therefore, no longer exists. As a result, the Company reduced the remaining
valuation allowance from approximately $53 million at December 31, 2002 to zero at December 31, 2003. See a further discussion on this matter in Note Q, Commitments and Contingencies.



c. Tax Gain on Generating Assets



The cost of transitioning to retail open access was mitigated, in part, by the sale of
Commonwealth Energy Systems (COM/Energy) (now a wholly owned subsidiary of NSTAR) non-nuclear generating assets. COM/Energy completed the sale of substantially all of its non-nuclear generating assets in 1998. Proceeds from the sale of these
assets amounted to approximately $453.9 million, or 6.1 times their book value of approximately $74.2 million. The proceeds from the sale, net of book value, transaction costs and certain other adjustments amounted to $358.6 million and are required
to be used for the benefit of COM/Energy customers under MDTE rate setting policies. In this instance, the amount was used to reduce transition costs of Cambridge Electric and ComElectric related to electric industry restructuring. COM/Energy
determined that this transaction was not a taxable event because it did not provide an economic benefit to its shareholders.



In order to complete its audit of COM/Energys tax returns for the years 1997, 1998 and 1999, the IRS needed to determine whether this transaction was taxable. The
local IRS examining agent filed a Request for Technical Advice with its National Office on June 5, 2003.



On August 28, 2003, NSTAR received a response from the IRS National Office to a Request for Technical Advice, requesting advice as to whether the gain on the sale of the COM/Energy non-nuclear generating assets in
1998 was a taxable transaction. The Technical Advice Memorandum upheld COM/Energys position. This ruling now completes the audits by the IRS of COM/Energys 1997, 1998 and 1999 federal income tax returns. This decision did not require the
Company to make tax and interest payments to the IRS of approximately $140 million.



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Note H. Pension and Other Postretirement Benefits



1. Pension



NSTAR sponsors a defined benefit retirement plan, the NSTAR Pension Plan (the Plan), that covers substantially all employees. NSTAR also maintains nonqualified retirement
plans for certain management employees.



The Plan uses December 31stfor the measurement date to determine its projected benefit obligation, fair value of plan assets, and net periodic benefit
costs for the following year.



The changes in benefit obligation and Plan
assets were as follows:



|                                                 |  |              |           |   |      |   |         |  
|------------------------------------------------ |  | ------------ | --------- | - | ---- | - | ------- | -
|                                                 |  | December 31, |          
|(in thousands)                                   |  | 2004         |           |   | 2003 |  
|Change in benefit obligation:                    |  |              |           |   |      |   |         |  
|Benefit obligation, beginning of the year        |  | $            | 961,029   |   |      | $ | 949,646 |  
|Service cost                                     |  |              | 19,038    |   |      |   | 17,976  |  
|Interest cost                                    |  |              | 60,165    |   |      |   | 58,826  |  
|Plan participants contributions                 |  |              | 61        |   |      |   | 72      |  
|Actuarial loss                                   |  |              | 90,693    |   |      |   | 4,920   |  
|Settlement payments                              |  |              | (18,588   | ) |      |   | (18,846 | )
|Benefits paid                                    |  |              | (53,000   | ) |      |   | (51,565 | )
|                                                 |  |              |           |   |      |   |         |  
|Benefit obligation, end of the year              |  | $            | 1,059,398 |   |      | $ | 961,029 |  
|                                                 |  |              |           |   |      |   |         |  
|Change in Plan assets:                           |  |              |           |   |      |   |         |  
|Fair value of Plan assets, beginning of the year |  | $            | 829,126   |   |      | $ | 665,897 |  
|Actual gain on Plan assets, net                  |  |              | 94,431    |   |      |   | 150,978 |  
|Employer contribution                            |  |              | 42,724    |   |      |   | 82,590  |  
|Plan participants contributions                 |  |              | 61        |   |      |   | 72      |  
|Settlement payments                              |  |              | (18,588   | ) |      |   | (18,846 | )
|Benefits paid                                    |  |              | (53,000   | ) |      |   | (51,565 | )
|                                                 |  |              |           |   |      |   |         |  
|Fair value of Plan assets, end of the year       |  | $            | 894,754   |   |      | $ | 829,126 |  
|                                                 |  |              |           |   |      |   |         |  



The Plans funded status was as
follows:



|                                   |  |              |          |   |      |   |          |  
|---------------------------------- |  | ------------ | -------- | - | ---- | - | -------- | -
|                                   |  | December 31, |         
|(in thousands)                     |  | 2004         |          |   | 2003 |  
|Funded status                      |  | $            | (164,644 | ) |      | $ | (131,903 | )
|Unrecognized actuarial net loss    |  |              | 443,437  |   |      |   | 403,312  |  
|Unrecognized transition obligation |  |              |         |   |      |   | 379      |  
|Unrecognized prior service cost    |  |              | (3,096   | ) |      |   | (2,962   | )
|                                   |  |              |          |   |      |   |          |  
|Net amount recognized              |  | $            | 275,697  |   |      | $ | 268,826  |  
|                                   |  |              |          |   |      |   |          |  



Amounts recognized in the accompanying
Consolidated Balance Sheets consisted of:



|                                       |  |              |         |   |      |   |         |  
|-------------------------------------- |  | ------------ | ------- | - | ---- | - | ------- | -
|                                       |  | December 31, |        
|(in thousands)                         |  | 2004         |         |   | 2003 |  
|Accrued retirement liability           |  | $            | (31,297 | ) |      | $ | (46,659 | )
|Intangible asset                       |  |              | 3,513   |   |      |   | 4,835   |  
|Accumulated other comprehensive income |  |              | 5,735   |   |      |   | 11,368  |  
|Prepaid pension                        |  |              | 297,746 |   |      |   |        |  
|Regulatory asset                       |  |              |        |   |      |   | 299,282 |  
|                                       |  |              |         |   |      |   |         |  
|Net amount recognized                  |  | $            | 275,697 |   |      | $ | 268,826 |  
|                                       |  |              |         |   |      |   |         |  



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The accumulated benefit obligation for the qualified retirement plan as of December 31, 2004 and 2003 were $870,730,000
and $843,609,000, respectively.



The projected benefit obligation, accumulated
benefit obligation and fair value of plan assets for the nonqualified retirement plan were $36,415,000, $31,297,000 and $0, respectively, as of December 31, 2004 and $34,317,000, $32,176,000 and $0, respectively, as of December 31, 2003.



Weighted average assumptions were as follows:



|                                                              |  |      |   |  |      |   |  |      |  
|------------------------------------------------------------- |  | ---- | - |  | ---- | - |  | ---- | -
|                                                              |  | 2004 |   |  | 2003 |   |  | 2002 |  
|Discount rate at the end of the year                          |  | 5.75 | % |  | 6.25 | % |  | 6.5  | %
|Expected return on Plan assets for the year (net of expenses) |  | 8.4  | % |  | 8.4  | % |  | 9.4  | %
|Rate of compensation increase at the end of the year          |  | 4.0  | % |  | 4.0  | % |  | 4.0  | %



The Plans discount rates are
based on rates of high quality corporate bonds of appropriate maturities as published by nationally recognized rating agencies consistent with the duration of the Companys plans and through periodic bond portfolio matching. The Plans
long-term rates of return are based on past performance and economic forecasts for the types of investments held in the Plan as well as the target allocation of the investments over a 20-year time period. This rate is presented net of both
administrative expenses and investment expenses, which have averaged approximately 0.6% for 2004 and 2003.



Components of net periodic benefit cost were as follows:



|                                      |  |                          |         |   |      |   |         |      |  |   |         |  
|------------------------------------- |  | ------------------------ | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                      |  | Years ended December 31, |        
|(in thousands)                        |  | 2004                     |         |   | 2003 |   |         | 2002 | 
|Service cost                          |  | $                        | 19,038  |   |      | $ | 17,976  |      |  | $ | 15,280  |  
|Interest cost                         |  |                          | 60,165  |   |      |   | 58,826  |      |  |   | 59,658  |  
|Expected return on Plan assets        |  |                          | (70,794 | ) |      |   | (58,917 | )    |  |   | (74,426 | )
|Amortization of prior service cost    |  |                          | 133     |   |      |   | 133     |      |  |   | 80      |  
|Amortization of transition obligation |  |                          | 379     |   |      |   | 601     |      |  |   | 601     |  
|Recognized actuarial loss             |  |                          | 26,931  |   |      |   | 33,514  |      |  |   | 13,530  |  
|                                      |  |                          |         |   |      |   |         |      |  |   |         |  
|Net periodic benefit cost             |  | $                        | 35,852  |   |      | $ | 52,133  |      |  | $ | 14,723  |  
|                                      |  |                          |         |   |      |   |         |      |  |   |         |  



Refer to Note I of these
Consolidated Financial Statements for more information on the impact of periodic benefit costs.



The following indicates the weighted average asset allocation percentage of the fair value of total Plan assets for each major type of Plan asset as of December 31stas well as the Plans target percentages and the permissible range:



|                  |  |             |   |  |                    |   |  |                    |   |           |           |  |                      
|----------------- |  | ----------- | - |  | ------------------ | - |  | ------------------ | - | --------- | --------- |  | ---------------------
|                  |  | Plan Assets |   |  | Target Percentages |   |  | Permissible Ranges |   | Benchmark
|                  |  | 2004        |   |  | 2003               |   |  |                    |  
|Asset Category    |  |             |   |  |                    |   |  |                    |   |           |           |  |                      
|Equity securities |  | 54          | % |  | 50                 | % |  | 50                 | % |           | 45% - 55% |  | Russell 300 Index    
|Debt securities   |  | 26          | % |  | 31                 | % |  | 25                 | % |           | 20% - 30% |  | Lehman Aggregate     
|Real Estate       |  | 5           | % |  | 5                  | % |  | 10                 | % |           | 5% - 15%  |  | Wilshire NAREIT Index
|Other             |  | 15          | % |  | 14                 | % |  | 15                 | % |           | 5% - 15%  |  |                      
|                  |  |             |   |  |                    |   |  |                    |   |           |           |  |                      
|Total             |  | 100         | % |  | 100                | % |  | 100                | % |           |           |  |                      
|                  |  |             |   |  |                    |   |  |                    |   |           |           |  |                      



In March 2003, the investment goals
were revised and new target percentages and permissible ranges were identified. As a result, the 2003 asset allocation percentages may not fall within the revised permissible ranges.



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The primary investment goal of the Plan is to achieve a total annualized return of 9% (before expenses) over the
long-term and to minimize unsystematic risk so that no single security or class of securities will have a disproportionate impact on the Plan. Risk is regularly evaluated, compared and benchmarked to plans with a similar investment strategy. NSTAR
currently uses 18 asset managers to manage its plan assets. Assets are diversified by both asset class (i.e., equities, bonds) and within these classes (i.e., economic sector, industry), such that, for each asset manager:



| |  |  | No more than 6% of an asset managers equity portfolio market value may be invested in one company
| | - |  | --------------------------------------------------------------------------------------------------



| |  |  | Each portfolio should be invested in at least 20 different companies in different industries, and
| | - |  | -------------------------------------------------------------------------------------------------



| |  |  | No more than 50% of each portfolios market value may be invested in one industry sector.
| | - |  | -----------------------------------------------------------------------------------------



Each asset manager may invest in domestic and international fixed income investments and may include government obligations, corporate
bonds, preferred stock, and asset-backed securities. In addition, no one asset manager may invest in more than 5% of any one security of an issuer, except the U.S. Government and its agencies.



Funded Status



At December 31, 2003, the accumulated benefit obligation of NSTARs qualified Plan
exceeded Plan assets. Therefore, NSTAR was required to recognize an additional minimum liability adjustment as prescribed by SFAS No. 87, Employers Accounting for Pensions (SFAS 87) and SFAS No. 132, Employers
Disclosures about Pensions and Postretirement Benefits.



As a result of
the additional minimum pension liability adjustment, the prepaid pension balance is removed from the balance sheet and a liability is recorded for the difference between the ABO and the plan assets. The net effect of this entry would ordinarily be
recorded, net of taxes, as a non-cash charge to Other Comprehensive Income (OCI) on the accompanying Consolidated Statements of Comprehensive Income and would not affect the results of operations.



On October 31, 2003, the MDTE approved NSTARs request for a reconciliation rate
adjustment mechanism related to pension and PBOP costs. As part of this ruling, NSTAR is allowed to record a regulatory asset in lieu of taking a charge to OCI for the additional minimum liability adjustment. As of December 31, 2003, NSTAR recorded
a regulatory asset of $299 million as the additional minimum liability adjustment. The regulatory asset is shown as part of Deferred debits in the accompanying Consolidated Balance Sheets. The fair value of Plan assets and the ABO are measured at
each year-end balance sheet date. The minimum liability is adjusted each year to reflect this measurement. When Plan assets exceed the ABO, the minimum liability is reversed. In 2004, due to positive Plan investment performance and Company
contributions over the last two years of approximately $120 million, the fair value of the Plans assets exceeded the Plans ABO at December 31, 2004. As a result, the minimum liability and regulatory asset have been removed and the
prepaid pension balance has been restored to the accompanying Consolidated Balance Sheet



NSTAR anticipates contributing approximately $35 million to the Plan in 2005.



The estimated benefit payments for the years after 2004 are as follows:



|               |  |   |        
|-------------- |  | - | -------
|(in thousands) |  |  
|2005           |  | $ | 60,574 
|2006           |  |   | 61,944 
|2007           |  |   | 64,946 
|2008           |  |   | 66,687 
|2009           |  |   | 75,545 
|2010 - 2014    |  |   | 400,205
|               |  |   |        
|Total          |  | $ | 729,901
|               |  |   |        



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2. Other Postretirement 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 until April 1, 2003 included reimbursement of certain Medicare premiums for certain retirees. Under certain circumstances, eligible retirees
are required to make contributions for postretirement benefits.



In December
2003, the FASB issued Staff Position (FSP) 106-1, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act provides for prescription drug benefits for
retirees over the age of 65 under a new Medicare Part D program. For employers like NSTAR, who currently provide retiree medical programs for former employees over the age of 65, there are subsidies available that are inherent in the Act. The Act
potentially entitles these employers to a direct tax-exempt federal subsidy. Pursuant to FSP 106-1, NSTAR elected to defer recognition of the provisions of this Act until further accounting guidance became effective.



In May 2004, the FASB issued FSP 106-2 effective July 2004 (retroactive to January 1, 2004)
to provide guidance on the accounting for the effects of the Act. The guidance requires that, when an employer initially accounts for the effects of the Act, the impact on the accumulated postretirement benefits obligation (APBO) should be accounted
for as an actuarial gain (assuming, no plan amendments are made). In accordance with this provision, NSTARs APBO was reduced approximately $51 million. In addition, since the subsidy affects the employers share of its plans costs,
the subsidy is included in measuring the costs of benefits attributable to current service. Therefore, the subsidy reduces service cost when it is recognized as a component of net periodic postretirement benefits cost. NSTARs adoption of FSP
106-2 resulted in a reduction to the 2004 net periodic postretirement benefit cost of approximately $7 million. However, due to the Companys pension and other postretirement benefits rate reconciliation adjustment mechanism that went into
effect on September 1, 2003, this reduction in cost does not have a material impact on earnings.



NSTARs other postretirement plans use December 31stfor the measurement date
to determine its benefit obligation, fair value of plan assets, and net periodic benefit costs for the following year.



The changes in benefit obligation and plan assets were as follows:



|                                                 |  |              |         |   |      |   |         |  
|------------------------------------------------ |  | ------------ | ------- | - | ---- | - | ------- | -
|                                                 |  | December 31, |        
|(in thousands)                                   |  | 2004         |         |   | 2003 |  
|Change in benefit obligation:                    |  |              |         |   |      |   |         |  
|Benefit obligation, beginning of the year        |  | $            | 595,483 |   |      | $ | 571,673 |  
|Service cost                                     |  |              | 5,828   |   |      |   | 7,076   |  
|Interest cost                                    |  |              | 33,395  |   |      |   | 35,383  |  
|Plan participants contributions                 |  |              | 1,835   |   |      |   | 1,517   |  
|Plan amendments                                  |  |              |        |   |      |   | 9,919   |  
|Actuarial gain                                   |  |              | (6,993  | ) |      |   | (868    | )
|Benefits paid                                    |  |              | (29,118 | ) |      |   | (29,217 | )
|                                                 |  |              |         |   |      |   |         |  
|Benefit obligation, end of the year              |  | $            | 600,430 |   |      | $ | 595,483 |  
|                                                 |  |              |         |   |      |   |         |  
|Change in plan assets:                           |  |              |         |   |      |   |         |  
|Fair value of plan assets, beginning of the year |  | $            | 280,032 |   |      | $ | 215,074 |  
|Actual gain on plan assets                       |  |              | 32,539  |   |      |   | 53,737  |  
|Employer contribution                            |  |              | 20,021  |   |      |   | 38,921  |  
|Plan participants contributions                 |  |              | 1,835   |   |      |   | 1,517   |  
|Benefits paid                                    |  |              | (29,118 | ) |      |   | (29,217 | )
|                                                 |  |              |         |   |      |   |         |  
|Fair value of plan assets, end of the year       |  | $            | 305,309 |   |      | $ | 280,032 |  
|                                                 |  |              |         |   |      |   |         |  



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The plans funded status was as follows:



|                                   |  |              |          |   |      |   |          |  
|---------------------------------- |  | ------------ | -------- | - | ---- | - | -------- | -
|                                   |  | December 31, |         
|(in thousands)                     |  | 2004         |          |   | 2003 |  
|Funded status                      |  | $            | (295,121 | ) |      | $ | (315,451 | )
|Unrecognized actuarial net loss    |  |              | 207,786  |   |      |   | 233,157  |  
|Unrecognized transition obligation |  |              | 14,575   |   |      |   | 16,396   |  
|Unrecognized prior service cost    |  |              | 9,570    |   |      |   | 10,855   |  
|                                   |  |              |          |   |      |   |          |  
|Net amount recognized              |  | $            | (63,190  | ) |      | $ | (55,043  | )
|                                   |  |              |          |   |      |   |          |  



Weighted average assumptions were as
follows:



|                                            |  |      |   |  |      |   |  |      |  
|------------------------------------------- |  | ---- | - |  | ---- | - |  | ---- | -
|                                            |  | 2004 |   |  | 2003 |   |  | 2002 |  
|Discount rate at the end of the year        |  | 5.75 | % |  | 6.25 | % |  | 6.5  | %
|Expected return on plan assets for the year |  | 8.0  | % |  | 8.0  | % |  | 9.0  | %



For measurement purposes, an 11%
weighted annual rate increase in per capita cost of covered medical claims was assumed for 2005. This rate is assumed to decrease gradually to 5% in 2015 and remain at that level thereafter. Dental claims and Medicare premiums (through April 1,
2003) are assumed to increase at a weighted annual rate of 4%.



A 1% change in
the assumed health care cost trend rate would have the following effects:



|                                                              |  |                      |        |          |   |         |  
|------------------------------------------------------------- |  | -------------------- | ------ | -------- | - | ------- | -
|                                                              |  | One-Percentage-Point |       
|(in thousands)                                                |  | Increase             |        | Decrease |  
|Effect on total service and interest cost components for 2004 |  | $                    | 6,694  |          | $ | (5,256  | )
|Effect on December 31, 2004 postretirement benefit obligation |  | $                    | 84,396 |          | $ | (67,845 | )



Components of net periodic benefit
cost were as follows:



|                                      |  |                          |         |   |      |   |         |      |  |   |         |  
|------------------------------------- |  | ------------------------ | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                      |  | Years ended December 31, |        
|(in thousands)                        |  | 2004                     |         |   | 2003 |   |         | 2002 | 
|Service cost                          |  | $                        | 5,828   |   |      | $ | 7,076   |      |  | $ | 5,204   |  
|Interest cost                         |  |                          | 33,395  |   |      |   | 35,383  |      |  |   | 33,170  |  
|Expected return on plan assets        |  |                          | (23,759 | ) |      |   | (19,088 | )    |  |   | (22,655 | )
|Amortization of prior service cost    |  |                          | 1,285   |   |      |   | 1,285   |      |  |   | (1,411  | )
|Amortization of transition obligation |  |                          | 1,821   |   |      |   | 1,821   |      |  |   | 5,616   |  
|Recognized actuarial loss             |  |                          | 9,598   |   |      |   | 13,303  |      |  |   | 6,588   |  
|                                      |  |                          |         |   |      |   |         |      |  |   |         |  
|Net periodic benefit cost             |  | $                        | 28,168  |   |      | $ | 39,780  |      |  | $ | 26,512  |  
|                                      |  |                          |         |   |      |   |         |      |  |   |         |  



Refer to Note I of these
Consolidated Financial Statements for more information on the impact of net periodic benefit costs.



NSTAR anticipates contributing approximately $20 million to its other postretirement benefit plans in 2005.



The estimated future benefit payments for the years after 2004 are as follows:



|               |  |   |        
|-------------- |  | - | -------
|(in thousands) |  |  
|2005           |  | $ | 27,779 
|2006           |  |   | 29,347 
|2007           |  |   | 30,816 
|2008           |  |   | 32,075 
|2009           |  |   | 33,532 
|2010 - 2014    |  |   | 187,027
|               |  |   |        
|Total          |  | $ | 340,576
|               |  |   |        



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The estimated expected cash flows from the Medicare subsidy for the years after 2004 are as follows:



|               |  |   |       
|-------------- |  | - | ------
|(in thousands) |  |  
|2005           |  | $ |      
|2006           |  |   | 2,182 
|2007           |  |   | 2,390 
|2008           |  |   | 2,603 
|2009           |  |   | 2,795 
|2010 - 2014    |  |   | 16,524
|               |  |   |       
|Total          |  | $ | 26,494
|               |  |   |       



The following indicates the weighted
average asset allocation percentages of the fair value of total Plan assets for each major type of Plan asset as of December 31stas well as the Plans target percentages and the permissible range:



|                  |  |             |   |  |                    |   |  |                    |   |           |           |  |                      
|----------------- |  | ----------- | - |  | ------------------ | - |  | ------------------ | - | --------- | --------- |  | ---------------------
|                  |  | Plan Assets |   |  | Target Percentages |   |  | Permissible Ranges |   | Benchmark
|Asset Category    |  | 2004        |   |  | 2003               |   |  |                    |  
|Equity securities |  | 50          | % |  | 50                 | % |  | 50                 | % |           | 45% - 55% |  | Russell 3000 Index   
|Debt securities   |  | 31          | % |  | 32                 | % |  | 30                 | % |           | 25% - 35% |  | Lehman Aggregate     
|Real Estate       |  | 10          | % |  | 9                  | % |  | 10                 | % |           | 5% - 15%  |  | Wilshire NAREIT Index
|Other             |  | 9           | % |  | 9                  | % |  | 10                 | % |           | 5% - 15%  |  |                     
|                  |  |             |   |  |                    |   |  |                    |   |           |           |  |                      
|Total             |  | 100         | % |  | 100                | % |  | 100                | % |           |           |  |                      
|                  |  |             |   |  |                    |   |  |                    |   |           |           |  |                      



The assets of the Companys PBOP
Plan are held in voluntary employees beneficiary association trusts.



The
plans primary investment goal is to outperform the return of the composite benchmark. The portfolio also seeks a level of volatility, which approximates that of the composite benchmark returns.



3. Savings Plan



NSTAR also provides a defined contribution 401(k) plan for substantially all employees.
Matching contributions (which are equal to 50% of the employees deferral up to 8% of eligible compensation) included in the accompanying Consolidated Statements of Income amounted to $8 million in 2004 and $9 million in 2003 and 2002.
Effective January 1, 2002, consistent with the Economic Growth and Tax Relief Reconciliation Act, the plan was amended to allow for increased maximum annual pre-tax contributions and additional catch-up pre-tax contributions for
participants age 50 or older, acceptance of other types of roll-over pre-tax funds from other plans and the option of reinvesting dividends paid on the NSTAR Common Share Fund or receiving such dividends in cash. The election to reinvest
dividends paid on the NSTAR Common Share Fund or receive the dividends in cash is subject to a freeze period beginning seven days prior to the date any dividend is paid. During this period, participants cannot change their election. Dividends are
paid to this plan four times a year on February 1, May 1, August 1 and November 1.



Note I. Pension and Postretirement Benefits Other Than Pensions (PBOP) Adjustment Mechanism Tariff Filing



On October 31, 2003, NSTAR received an order from the MDTE regarding NSTARs request (filed on April 16, 2003) for the approval of a reconciliation rate adjustment
mechanism (PAM) for recovery of costs associated with the Companys obligation to provide its employees qualified pension and PBOP benefits. Prior to the PAM order, the Company had accounted for these obligations in accordance with an
Accounting Order received from the MDTE in December 2002.



The PAM order
authorizes NSTAR to recover its qualified pension and PBOP expenses through a reconciling rate mechanism. This mechanism removes the volatility in earnings that may have resulted from requirements of existing accounting standards and provides for an
annual filing and rate adjustment with the MDTE. This order effectuates the



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Accounting Order, which allowed NSTAR to record a regulatory asset in lieu of taking a charge to OCI at December 31, 2002 for the additional minimum
liability in accordance with SFAS 87. In addition, the order revised the effective date included in the Accounting Order on which the Company could begin to defer the difference between the level of qualified pension and PBOP expense included in
rates and the amounts that are required to be recorded under the pension and PBOP accounting rules to September 1, 2003. This date coincides to the expiration of NSTARs utility subsidiaries four-year distribution rate freeze. As a
result, NSTAR recognized $18.0 million of expenses in the third quarter of 2003 that had been deferred earlier in the year. In accordance with the PAM order, the Company recognized in 2003 $16.3 million of revenue related to carrying charges on the
net prepaid balance. This carrying charge was collected from customers during 2004. In 2004, the Company recognized $17.4 million of revenue related to carrying charges on the net prepaid balance. This carrying charge will be collected from
customers during 2005.



On November 20, 2003, both NSTAR and the Massachusetts
Attorney General filed motions with the MDTE for reconsideration of its PAM order. On November 19, 2004, the MDTE denied the request for reconsideration for both NSTAR and the Massachusetts Attorney General.



Note J. Stock-Based Compensation



NSTARs Share Incentive Plan (the Plan) permits a variety of stock and stock-based
awards, including stock options and deferred (non-vested) stock to be granted to key employees. The Plan limits the terms of awards to ten years. Subject to adjustment for stock-splits and similar events, the aggregate number of common shares that
may be awarded under the Plan is four million as a result of an amendment to the Plan approved by shareholders in 2002 that increased the number of shares available for issuance from two million to four million, including shares issued in lieu of or
upon reinvestment of dividends arising from awards. The weighted average grant date fair value of the deferred stock issued during 2004, 2003 and 2002 was $48.41, $43.20 and $45.24, respectively. During 2004, 108,350 deferred shares and 316,000
ten-year non-qualified stock options were granted under the Plan. During 2003, 109,900 deferred shares and 324,000 ten-year non-qualified stock options were granted under the Plan. During 2002, 95,300 deferred shares and 265,000 ten-year
non-qualified stock options were granted. The options were granted at the full market price of the common shares on the date of the grant. All the awards vest ratably over a three-year period.



Stock option activity of the Plan was as follows:



|                                   |  |              |   |  |                              |       |              |           |   |                              |   |              |  |           |                              |  |   |      
|---------------------------------- |  | ------------ | - |  | ---------------------------- | ----- | ------------ | --------- | - | ---------------------------- | - | ------------ |  | --------- | ---------------------------- |  | - | -----
|                                   |  | 2004Activity |   |  | WeightedAverageExercisePrice |       | 2003Activity |           |   | WeightedAverageExercisePrice |   | 2002Activity |  |           | WeightedAverageExercisePrice
|Options outstanding at January 1   |  | 1,212,769    |   |  | $                            | 42.02 |              | 1,046,869 |   |                              | $ | 40.14        |  | 967,602   |                              |  | $ | 38.80
|Options granted                    |  | 316,000      |   |  | $                            | 48.41 |              | 324,000   |   |                              | $ | 43.20        |  | 265,000   |                              |  | $ | 45.24
|Options exercised                  |  | (72,600      | ) |  | $                            | 41.05 |              | (140,667  | ) |                              | $ | 30.53        |  | (152,033  | )                            |  | $ | 39.92
|Options forfeited                  |  |             |   |  | $                            |      |              | (17,433   | ) |                              | $ | 43.56        |  | (33,700   | )                            |  | $ | 42.92
|                                   |  |              |   |  |                              |       |              |           |   |                              |   |              |  |           |                              |  |   |      
|Options outstanding at December 31 |  | 1,456,169    |   |  | $                            | 43.45 |              | 1,212,769 |   |                              | $ | 42.02        |  | 1,046,869 |                              |  | $ | 40.14
|                                   |  |              |   |  |                              |       |              |           |   |                              |   |              |  |           |                              |  |   |      



Summarized information regarding stock
options outstanding at December 31, 2004:



|                        |  |                   |  |                                                 |  |                              |       |                   |         |                              |   |      
|----------------------- |  | ----------------- |  | ----------------------------------------------- |  | ---------------------------- | ----- | ----------------- | ------- | ---------------------------- | - | -----
|                        |  |                   |  | Options Outstanding                             |  | Options Exercisable         
|Range ofExercise Prices |  | NumberOutstanding |  | WeightedAverageRemainingContractualLife (Years) |  | WeightedAverageExercisePrice |       | NumberOutstanding |         | WeightedAverageExercisePrice
|$25.75 - $26.00         |  | 48,400            |  | 2.45                                            |  | $                            | 25.75 |                   | 48,400  |                              | $ | 25.75
|$39.75 - $41.38         |  | 231,835           |  | 3.26                                            |  | $                            | 40.41 |                   | 231,835 |                              | $ | 40.41
|$44.38                  |  | 151,600           |  | 5.40                                            |  | $                            | 44.38 |                   | 151,600 |                              | $ | 44.38
|$39.70                  |  | 136,334           |  | 6.40                                            |  | $                            | 39.70 |                   | 136,334 |                              | $ | 39.70
|$44.12 - $45.33         |  | 259,000           |  | 7.30                                            |  | $                            | 45.24 |                   | 173,530 |                              | $ | 45.24
|$43.20                  |  | 313,000           |  | 8.33                                            |  | $                            | 43.20 |                   | 103,290 |                              | $ | 43.20
|$48.41                  |  | 316,000           |  | 9.33                                            |  | $                            | 48.41 |                   |        |                              |   |     



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There were 844,989, 672,473 and 614,989 stock options exercisable on December 31, 2004, 2003 and 2002, respectively. The
weighted average exercise price of these options exercisable are $41.50, $40.83 and $37.62, respectively.



The stock options granted during 2004, 2003 and 2002 have a weighted average grant date fair value of $3.74, $3.85 and $5.97, respectively. The fair value was estimated using the Black-Scholes option-pricing model
with the following weighted average assumptions:



|                        |  |      |   |  |      |   |  |      |  
|----------------------- |  | ---- | - |  | ---- | - |  | ---- | -
|                        |  | 2004 |   |  | 2003 |   |  | 2002 |  
|Expected life (years)   |  | 4.0  |   |  | 4.0  |   |  | 4.0  |  
|Risk-free interest rate |  | 3.39 | % |  | 2.54 | % |  | 4.31 | %
|Volatility              |  | 15   | % |  | 18   | % |  | 21   | %
|Dividends               |  | 4.90 | % |  | 4.97 | % |  | 4.77 | %



Compensation cost recognized in the
accompanying Consolidated Statements of Income for deferred share awards in 2004, 2003 and 2002 was $4,282,561, $3,530,719 and $2,737,216, respectively.



Note K. Capital Stock



1. Common Shares



Common share issuances and repurchases in 2002 through 2004 were as follows:



|                                                             |  |                 |  |                |        |                        |   |         |  
|------------------------------------------------------------ |  | --------------- |  | -------------- | ------ | ---------------------- | - | ------- | -
|(in thousands)                                               |  | Number ofShares |  | TotalPar Value |        | Premium onCommonShares |  
|Balance at December 31, 2001                                 |  | 53,033          |  | $              | 53,033 |                        | $ | 873,664 |  
|Share Incentive Plan                                         |  |                |  |                |       |                        |   | (2,787  | )
|                                                             |  |                 |  |                |        |                        |   |         |  
|Balance at December 31, 2002                                 |  | 53,033          |  |                | 53,033 |                        |   | 870,877 |  
|Share Incentive Plan                                         |  |                |  |                |       |                        |   | (4,656  | )
|                                                             |  |                 |  |                |        |                        |   |         |  
|Balance at December 31, 2003                                 |  | 53,033          |  |                | 53,033 |                        |   | 866,221 |  
|Share Incentive Plan issuance                                |  | 86              |  |                | 86     |                        |   | 3,977   |  
|Share Incentive Plan                                         |  |                |  |                |       |                        |   | (4,871  | )
|Dividend Reinvestment and Direct Common Shares Purchase Plan |  | 156             |  |                | 156    |                        |   | 7,402   |  
|                                                             |  |                 |  |                |        |                        |   |         |  
|Balance at December 31, 2004                                 |  | 53,275          |  | $              | 53,275 |                        | $ | 872,729 |  
|                                                             |  |                 |  |                |        |                        |   |         |  



Dividends declared per common share
were $2.245, $2.175 and $2.13 in 2004, 2003 and 2002, respectively.



2. Cumulative Preferred Stock of Subsidiary



Non-mandatory redeemable series:



Par value $100 per share, 2,660,000
shares authorized and 430,000 shares issued and outstanding:



|                                         |  |                           |  |                       |         |                   |   |                   |        |   |       
|---------------------------------------- |  | ------------------------- |  | --------------------- | ------- | ----------------- | - | ----------------- | ------ | - | ------
|(in thousands, except per share amounts) |  |                           |  |                       |         |                  
|                                         |  |                           |  |                      
|Series                                   |  | Current SharesOutstanding |  | RedemptionPrice/Share |         | December 31, 2004 |   | December 31, 2003
|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
|                                         |  |                           |  |                       |         |                   |   |                   |        |   |       



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Note L. Indebtedness



1. Long-Term Debt



NSTARs long-term debt consisted of the following:



|                                                                            |  |              |           |   |      |   |           |  
|--------------------------------------------------------------------------- |  | ------------ | --------- | - | ---- | - | --------- | -
|                                                                            |  | December 31, |          
|(in thousands)                                                              |  | 2004         |           |   | 2003 |  
|Mortgage Bonds/Notes, collateralized by property of operating subsidiaries: |  |              |           |   |      |   |           |  
|6.54%, due September 2007                                                   |  | $            | 4,286     |   |      | $ | 5,714     |  
|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    |  
|6.924%, due June 2021                                                       |  |              | 102,743   |   |      |   | 105,524   |  
|Notes:                                                                      |  |              |           |   |      |   |           |  
|Variable Rate (3.0275% in 2004 and 1.895% in 2003) due May 2006             |  |              | 150,000   |   |      |   | 150,000   |  
|9.50%, due December 2004                                                    |  |              |          |   |      |   | 1,000     |  
|7.62%, due November 2006                                                    |  |              | 20,000    |   |      |   | 20,000    |  
|8.70%, due March 2007                                                       |  |              | 5,000     |   |      |   | 5,000     |  
|9.55%, due December 2007                                                    |  |              | 4,286     |   |      |   | 5,714     |  
|7.70%, due March 2008                                                       |  |              | 10,000    |   |      |   | 10,000    |  
|8.0%, due February 2010                                                     |  |              | 500,000   |   |      |   | 500,000   |  
|9.37%, due January 2012                                                     |  |              | 8,421     |   |      |   | 9,474     |  
|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    |  
|8.47%, due March 2023                                                       |  |              | 15,000    |   |      |   | 15,000    |  
|Debentures:                                                                 |  |              |           |   |      |   |           |  
|Floating Rate (2.57% in 2004 and 1.65% in 2003) due October 2005            |  |              | 100,000   |   |      |   | 100,000   |  
|7.80%, due May 2010                                                         |  |              | 125,000   |   |      |   | 125,000   |  
|4.875%, due October 2012                                                    |  |              | 400,000   |   |      |   | 400,000   |  
|4.875%, due April 2014                                                      |  |              | 300,000   |   |      |   |          |  
|7.80%, due March 2023                                                       |  |              |          |   |      |   | 181,000   |  
|Sewage facility revenue bonds, due through 2015                             |  |              | 16,591    |   |      |   | 18,248    |  
|Massachusetts Industrial Finance Agency (MIFA) bonds:                       |  |              |           |   |      |   |           |  
|5.75%, due February 2014                                                    |  |              | 15,000    |   |      |   | 15,000    |  
|Transition Property Securitization Certificates:                            |  |              |           |   |      |   |           |  
|6.62%, due March 2005                                                       |  |              | 7,296     |   |      |   | 74,727    |  
|6.91%, due September 2007                                                   |  |              | 170,876   |   |      |   | 170,876   |  
|7.03%, due March 2010                                                       |  |              | 171,624   |   |      |   | 171,624   |  
|                                                                            |  |              |           |   |      |   |           |  
|                                                                            |  |              | 2,256,123 |   |      |   | 2,213,901 |  
|Unamortized debt discount                                                   |  |              | (5,476    | ) |      |   | (4,316    | )
|Amounts due within one year                                                 |  |              | (149,245  | ) |      |   | (230,033  | )
|                                                                            |  |              |           |   |      |   |           |  
|Total long-term debt                                                        |  | $            | 2,101,402 |   |      | $ | 1,979,552 |  
|                                                                            |  |              |           |   |      |   |           |  



On March 16, 2004, Boston Edison
redeemed the entire outstanding balance of $181 million aggregate principal amount of its 7.80% Debentures due March 15, 2023. The redemption also included payment of premium plus accrued interest of approximately $6.1 million. On April 16, 2004,
Boston Edison issued $300 million of ten-year fixed rate (4.875%) Debentures. The net proceeds were used to repay outstanding short-term debt balances incurred, in part, to pay the redemption price of the 7.80% Debentures. The premium paid to redeem
the 7.80% Debentures will be amortized over ten years, the term of the new 4.875% Debentures.



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Sewage facility revenue bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature
through 2015. Scheduled redemptions of $1.65 million were made in 2004 and 2003. The interest rate of the bonds was 7.375% for both 2004 and 2003.



The 5.75% tax-exempt unsecured MIFA bonds due 2014 were 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.



The aggregate principal amounts of
NSTAR long-term debt (including securitization certificates and sinking fund requirements) due in the five years subsequent to 2004 are approximately $149 million in 2005, $248 million in 2006, $83 million in 2007, $86 million in 2008 and $76
million in 2009.



2. Financial Covenant
Requirements



NSTAR and Boston Edison have no financial covenant requirements
under their respective long-term debt arrangements. ComElectric, Cambridge Electric and NSTAR Gas have financial covenant requirements under their long-term debt arrangements and were in compliance at December 31, 2004 and 2003. NSTARs
long-term debt other than the Mortgage Bonds/Notes of NSTAR Gas and Medical Area Total Energy Plant, Inc., a wholly owned subsidiary of AES, is unsecured.



The Transition Property Securitization Certificates held by Boston Edisons subsidiary, BEC Funding LLC, are collaterized with a securitized regulatory asset with a
balance of $357.2 million and $425.4 million as of December 31, 2004 and 2003, respectively. Boston Edison, as servicing agent for BEC Funding LLC, collected $96.0 million in 2004. These Certificates are non-recourse to Boston Edison.



In November 2004, NSTAR restructured its three-year, $175 million revolving credit agreement
that was set to expire on November 14, 2005 into a five-year, $175 million revolving credit agreement that expires in November 2009. At December 31, 2004 and 2003, there were no amounts outstanding under the current and previous revolving credit
agreement. This credit facility serves as a backup to NSTARs $175 million commercial paper program that, at December 31, 2004 and 2003, had $5 million and $1.5 million outstanding, respectively. Under the terms of the current credit agreement,
NSTAR is required to maintain a maximum total consolidated debt to total capitalization ratio of not greater than 65% at all times, excluding Transition Property Securitization Certificates, and excluding Accumulated other comprehensive income
(loss) from Common equity. The previous arrangement also required NSTAR to maintain a ratio of consolidated earnings before interest and taxes to consolidated total interest expense of not less than 2 to 1 for each period of four consecutive fiscal
quarters. Commitment fees must be paid on the total agreement amount. At December 31, 2004 and 2003, NSTAR was in full compliance with all of the aforementioned covenants.



In December 2003, Boston Edison filed a shelf registration with the SEC to allow Boston Edison to issue up to $500 million in debt
securities. The registration became effective on January 9, 2004. On April 1, 2004, the MDTE approved the issuance by Boston Edison of up to $500 million of debt securities from time to time on or before December 31, 2005. On April 16, 2004, Boston
Edison sold $300 million of ten-year fixed rate (4.875%) Debentures under this shelf registration. The net proceeds were primarily used to repay outstanding short-term debt balances.



As of September 28, 2004, Boston Edison has approval from the FERC to issue short-term debt securities from time to time on or before
December 31, 2006, with maturity dates no later than December 31, 2007, in amounts such that the aggregate principal does not exceed $450 million at any one time. In addition, in November 2004, Boston Edison restructured its $350 million revolving
credit agreement that expired in November 2004 into a five-year, $350 million revolving credit agreement that expires in November 2009. However, unless Boston Edison receives necessary approvals from the MDTE, the credit agreement will expire 364
days from the date of the first draw under the agreement. At December 31, 2004 and 2003, there were no amounts outstanding under



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the current and previous revolving credit agreement. This credit facility serves as backup to Boston Edisons $350 million commercial paper program that
had a $46.5 million and $182.5 million balance at December 31, 2004 and 2003, respectively. Under the terms of the current agreement, Boston Edison is required to maintain a consolidated maximum total debt to capitalization ratio of not greater than
65% at all times, excluding Transition Property Securitization Certificates, and excluding Accumulated other comprehensive income (loss) from Common equity. The previous agreement required a total debt to capitalization ratio of not greater than
60%. At December 31, 2004 and 2003, Boston Edison was in full compliance with all of its covenants in connection with its short-term credit facilities.



In addition, as of December 31, 2004, ComElectric, Cambridge Electric and NSTAR Gas, collectively, have $145 million available under several lines of credit and had
$109.9 million and $55.1 million outstanding under these lines of credit at December 31, 2004 and 2003, respectively. As of September 28, 2004, ComElectric and Cambridge Electric have FERC authorization to issue short-term debt securities from
time-to-time on or before November 30, 2006 and June 27, 2006, with maturity dates no later than November 30, 2007 and June 27, 2007, respectively, in amounts such that the aggregate principal does not exceed $125 million and $60 million,
respectively, at any one time. NSTAR Gas is not required to seek approval from FERC to issue short-term debt.



Interest rates on the outstanding borrowings generally are money market rates and averaged 1.38% and 1.28% in 2004 and 2003, respectively. In aggregate, short-term borrowings totaled $161.4 million and $239.1 million
at December 31, 2004 and 2003, respectively.



Note M. 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 $12.5 million and $16.5 million for 2004 and 2003, respectively, approximate fair value due to the short-term nature of these securities.



2. Indebtedness (Excluding Notes Payable)



The fair values of long-term indebtedness are based upon the quoted market
prices of similar issues. Carrying amounts and fair values as of December 31, 2004 and 2003 were as follows:



|                                                      |  |                |           |           |   |                |  |           |           |  |   |          
|----------------------------------------------------- |  | -------------- | --------- | --------- | - | -------------- |  | --------- | --------- |  | - | ---------
|                                                      |  | 2004           |           | 2003     
|(in thousands)                                        |  | CarryingAmount |           | FairValue |   | CarryingAmount |  | FairValue
|Long-term indebtedness (including current maturities) |  | $              | 2,250,647 |           | $ | 2,483,220      |  | $         | 2,209,585 |  | $ | 2,485,190



Note N. Segment and Related
Information



For the purpose of providing segment information,
NSTARs principal operating segments, or its traditional core businesses, are the electric and natural gas utilities that provide energy delivery services in 107 cities and towns in Massachusetts.



The unregulated operating segment engages in business activities that include district energy
operations, telecommunications and liquefied natural gas service. Amounts shown on the following table for 2004, 2003 and 2002 include the allocation of NSTARs (parent company) results of operations and assets, net of inter-company
transactions, and primarily consist of interest charges and investment assets, respectively, to these business segments. The allocation of parent company charges is based on an indirect allocation of the parent companys investment relating to
these various business segments.



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The unregulated net income for 2004 as compared to 2003 reflects the absence of operations in 2004 at Blackstone Station
due to its sale in 2003 and the resulting impact of decreased income on NSTAR Steam Corporation, offset by a higher gross margin at Advanced Energy Systems Inc. resulting from increased steam sales and higher demand revenues. The unregulated net
income for 2003 reflects an increase in NSTARs wholesale telecommunications business and the sale of Blackstone Station that generated a $2.6 million gain. Offsetting these increases in unregulated income were decreases at Advanced Energy
Systems primarily due to fuel price increases. On December 24, 2003, NSTAR abandoned the 11.6 million shares of RCN common stock and recorded a pre-tax charge of $6.8 million including expenses. Offsetting the 2003 RCN abandonment loss is the
recognition of $6.8 million of tax benefits resulting from unanticipated capital gain transactions.



In addition, the unregulated net loss for 2002 reflects reductions in the carrying value of NSTARs investment and its ultimate discontinuance of its Northwind chilled water operations in the amount of $1
million. Effective September 30, 2002, certain chilled water operations were terminated in accordance with its contractual obligations. The net loss for 2002 for the unregulated operations segment also includes the impact of non-cash, after-tax
charges of $17.7 million or $0.33 per share, related to the write-down of NSTARs investment in RCN.



Excluding the impact of transactions related to NSTARs investment in RCN, NSTARs chilled water operations and the negative effect of the allocation of parent company losses, the unregulated operations
segment would otherwise reflect a minimal level of net income for 2002.



The
unregulated net expenditures for property decreased as compared to 2003 primarily due to the absence in 2004 of expenditures for MATEPs expansion project that was placed into service in late 2003.



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##### Table of Contents

|                                                                    |  |      |           |      |   |           |  |   |           |  
|------------------------------------------------------------------- |  | ---- | --------- | ---- | - | --------- |  | - | --------- | -
|(in thousands)                                                      |  | 2004 |           | 2003 |   | 2002      | 
|Operating revenues                                                  |  |      |           |      |   |           |  |   |           |  
|Electric utility operations                                         |  | $    | 2,352,944 |      | $ | 2,333,267 |  | $ | 2,255,636 |  
|Gas utility operations                                              |  |      | 492,338   |      |   | 465,208   |  |   | 331,775   |  
|Unregulated operations                                              |  |      | 109,050   |      |   | 113,236   |  |   | 103,214   |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Consolidated total                                                  |  | $    | 2,954,332 |      | $ | 2,911,711 |  | $ | 2,690,625 |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Depreciation and amortization                                       |  |      |           |      |   |           |  |   |           |  
|Electric utility operations                                         |  | $    | 212,126   |      | $ | 202,899   |  | $ | 210,067   |  
|Gas utility operations                                              |  |      | 20,191    |      |   | 18,945    |  |   | 17,643    |  
|Unregulated operations                                              |  |      | 14,627    |      |   | 13,672    |  |   | 11,523    |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Consolidated total                                                  |  | $    | 246,944   |      | $ | 235,516   |  | $ | 239,233   |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Operating income tax expense (benefit)                              |  |      |           |      |   |           |  |   |           |  
|Electric utility operations                                         |  | $    | 97,680    |      | $ | 103,697   |  | $ | 96,117    |  
|Gas utility operations                                              |  |      | 15,098    |      |   | 15,948    |  |   | 9,677     |  
|Unregulated operations                                              |  |      | 3,460     |      |   | 1,764     |  |   | 1,319     |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Consolidated total                                                  |  | $    | 116,238   |      | $ | 121,409   |  | $ | 107,113   |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Equity income in investments accounted for by the equity method (a) |  |      |           |      |   |           |  |   |           |  
|Electric utility operations                                         |  | $    | 1,607     |      | $ | 2,205     |  | $ | 2,667     |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Interest charges                                                    |  |      |           |      |   |           |  |   |           |  
|Electric utility operations                                         |  | $    | 128,306   |      | $ | 134,513   |  | $ | 145,691   |  
|Gas utility operations                                              |  |      | 15,677    |      |   | 14,203    |  |   | 14,782    |  
|Unregulated operations                                              |  |      | 9,722     |      |   | 8,496     |  |   | 12,108    |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Consolidated total                                                  |  | $    | 153,705   |      | $ | 157,212   |  | $ | 172,581   |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Segment net income (loss)                                           |  |      |           |      |   |           |  |   |           |  
|Electric utility operations                                         |  | $    | 156,679   |      | $ | 150,249   |  | $ | 156,169   |  
|Gas utility operations                                              |  |      | 25,801    |      |   | 24,441    |  |   | 15,298    |  
|Unregulated operations                                              |  |      | 6,001     |      |   | 6,884     |  |   | (9,760    | )
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Consolidated total                                                  |  | $    | 188,481   |      | $ | 181,574   |  | $ | 161,707   |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Goodwill                                                            |  |      |           |      |   |           |  |   |           |  
|Electric utility operations                                         |  | $    | 364,653   |      | $ | 375,172   |  | $ | 385,691   |  
|Gas utility operations                                              |  |      | 62,217    |      |   | 63,950    |  |   | 65,683    |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Consolidated total                                                  |  | $    | 426,870   |      | $ | 439,122   |  | $ | 451,374   |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Equity Investments                                                  |  |      |           |      |   |           |  |   |           |  
|Electric utility operations                                         |  | $    | 13,887    |      | $ | 15,322    |  | $ | 19,845    |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Net expenditures for property                                       |  |      |           |      |   |           |  |   |           |  
|Electric utility operations                                         |  | $    | 272,794   |      | $ | 240,699   |  | $ | 305,153   |  
|Gas utility operations                                              |  |      | 35,262    |      |   | 30,167    |  |   | 28,238    |  
|Unregulated operations                                              |  |      | 5,331     |      |   | 36,789    |  |   | 34,693    |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Consolidated total                                                  |  | $    | 313,387   |      | $ | 307,655   |  | $ | 368,084   |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Segment assets                                                      |  |      |           |      |   |           |  |   |           |  
|Electric utility operations                                         |  | $    | 6,259,216 |      | $ | 5,422,411 |  | $ | 5,464,152 |  
|Gas utility operations                                              |  |      | 656,554   |      |   | 679,813   |  |   | 656,473   |  
|Unregulated operations                                              |  |      | 201,459   |      |   | 229,927   |  |   | 217,829   |  
|                                                                    |  |      |           |      |   |           |  |   |           |  
|Consolidated total                                                  |  | $    | 7,117,229 |      | $ | 6,332,151 |  | $ | 6,338,454 |  
|                                                                    |  |      |           |      |   |           |  |   |           |  

---

|(a) | The equity income from equity investments is included in other income, net on the accompanying Consolidated Statements of Income.
|--- | ---------------------------------------------------------------------------------------------------------------------------------



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Note O. Contracts for the Purchase of Energy



1. NSTAR Electric Purchase Power Agreements



In accordance with the 1997 Massachusetts Electric Restructuring Act (the Act), NSTAR divested of its generation facilities and replaced
that load requirement through purchase power contracts, both with existing contracts and with newly executed contracts. As a result, NSTAR has been required to enter into purchase power contracts of varying lengths to satisfy its electric load
requirements. NSTAR has limitations, as mandated by the MDTE, as to the length of these contracts. As Massachusetts distribution companies, NSTAR Electric is required to obtain and resell power to retail customers through either default or standard
offer service for those who choose not to buy energy from a competitive energy supplier. Default service is provided to customers who have entered NSTARs service territory after the effective date of the Act and whose rate is intended to
reflect current market conditions. Standard offer service is provided to customers who were customers at the time of the Act and whose rate is determined by the MDTE to guarantee overall rate reductions. Standard offer service will expire on
February 28, 2005. NSTAR has entered into agreements ranging in length from three to twelve months for its default service power supply. For its standard offer service power supply, NSTAR assigned its existing long-term contracts to meet this load
requirement.



To a certain extent, NSTAR supplements its load requirements
through existing long-term contracts. NSTAR Electric, during 2003 and 2004, initiated a process to auction off certain purchase power agreements under which it had entitlements to under long-term contracts. One contract in which NSTAR Electric had
entitlements to approximately 300 MW of the 1,100 MW of capacity, originally included in the auction, expired on December 31, 2004. Also in 2004, NSTAR Electric executed agreements to buy-out or restructure twelve of its purchase power agreements.
These buy-out/restructuring agreements provide no economic benefit to NSTAR Electric and, therefore, the agreements contract termination costs will be recorded on the accompanying Consolidated Financial Statements. These agreements constitute
approximately 685 MW of the 1,100 MW of capacity, originally included in the auction, and reduce the amount of above-market costs that NSTAR Electric will collect from its customers through its transition charges. As of December 31, 2004, four of
these agreements have received MDTE approval and were recognized. Two of the four agreements require NSTAR Electric to make monthly payments through December 2008 totaling approximately $80 million. The other two agreements require NSTAR Electric to
make monthly payments through September 2011 totaling approximately $125 million.



On January 7, 2005, NSTAR Electric received approval from the MDTE for an additional four agreements that are anticipated to be completed by February 2005. These four agreements were binding as of December 31, 2004 but were contingent upon
regulatory approval. Since the contingency was removed during February 2005, NSTAR recorded the contract termination cost as of December 31, 2004. One of the four agreements requires NSTAR Electric to make net monthly payments through September 2011
totaling approximately $416 million. The other three agreements require NSTAR Electric to make net monthly payments through September 2016 totaling approximately $490 million. NSTAR Electric anticipates making these cash payments from funds
generated from operations and will be fully recovered through NSTAR Electrics transition charge.



The total amount currently recognized for obligations relating to eight of the twelve contracts is approximately $852 million (in present day dollars); approximately $171 million as a component of current liabilities
- power contracts and $681 million as a component of Deferred credits - power contracts on the accompanying Consolidated Balance Sheets. NSTAR Electric has recorded a corresponding regulatory asset to reflect the full future recovery of these
payments through its transition charge. This recognition represents a non-cash increase to assets and liabilities.



Also in January 2005, the MDTE approved the remaining four contracts with two suppliers that reduced the overall amount of transition costs to be paid for above-market
contracts. These contracts are buy-out arrangements whereby NSTAR Electric has committed to pay amounts for the full release of its obligation under previous purchase power agreements. On August 31, 2004, NSTAR Electric filed with the MDTE a
proposed



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financing plan that seeks approval for full recovery of these buy-out costs and the issuance of $674.5 million of transition property securitization bonds to
provide the funds for these buy-out agreements. The MDTE approved the financing plan in January 2005. On February 15, 2005, the bonds were priced at a weighted average yield of 4.15%. NSTAR expects the securitization financing to close in March
2005.



Capacity Costs



Capacity costs of long-term contracts reflect NSTAR Electrics proportionate share of
capital and fixed operating costs of certain generating units. In 2004, these costs were attributed to 529.7 MW of capacity purchased. Energy costs are paid to generators based on a price per kWh actually received into NSTAR Electrics
distribution system and are included in the total cost. Total capacity purchased in 2004 was 1,201.4 MW.



Information related to long-term power contracts during 2004 was as follows:



|                             |  |                                 |  |                            |  |                                                    |  |   |               |   |                                                          |   |         |  |   |       
|---------------------------- |  | ------------------------------- |  | -------------------------- |  | -------------------------------------------------- |  | - | ------------- | - | -------------------------------------------------------- | - | ------- |  | - | ------
|                             |  |                                 |  |                            |  | NSTAR Electrics Proportionate share(in thousands)
|Fuel Type of Generating Unit |  | Range ofContractExpirationDates |  | Units of CapacityPurchased |  | 2004CapacityCost                                   |  |   | 2004TotalCost |   | Capacity ChargeObligationThrough ContractExpiration Date
|                             |  | % Range                         |  | Total MW                   |  |                                                    | 
|Natural Gas                  |  | 2004-2017                       |  | 11.1-100                   |  | 720.6                                              |  | $ | 121,131       |   |                                                          | $ | 350,923 |  | $ | 24,775
|Nuclear                      |  | 2004-2012                       |  | 2.5-43.5                   |  | 311.2                                              |  |   | (65           | ) |                                                          |   | 125,650 |  |   | 173   
|Refuse                       |  | 2015                            |  | 100                        |  | 76.9                                               |  |   |              |   |                                                          |   | 59,982  |  |   |      
|Hydro                        |  | 2014-2023                       |  | 100                        |  | 24.7                                               |  |   |              |   |                                                          |   | 9,364   |  |   |      
|Oil                          |  | 2005-2019                       |  | 100                        |  | 68.0                                               |  |   | 3,437         |   |                                                          |   | 3,959   |  |   | 35,598
|                             |  |                                 |  |                            |  |                                                    |  |   |               |   |                                                          |   |         |  |   |       
|Total                        |  |                                 |  |                            |  | 1,201.4                                            |  | $ | 124,503       |   |                                                          | $ | 549,878 |  | $ | 60,546
|                             |  |                                 |  |                            |  |                                                    |  |   |               |   |                                                          |   |         |  |   |       



NSTAR Electrics total capacity
and/or energy costs associated with these contracts in 2004, 2003 and 2002 were approximately $550 million, $569 million and $666 million, respectively. NSTAR Electrics capacity charge obligations under these contracts for the years after 2004
are as follows:



|                 |  |                          |       
|---------------- |  | ------------------------ | ------
|(in thousands)   |  | CapacityChargeObligation
|2005             |  | $                        | 28,546
|2006             |  |                          | 2,180 
|2007             |  |                          | 2,200 
|2008             |  |                          | 2,219 
|2009             |  |                          | 2,237 
|Years thereafter |  |                          | 23,164
|                 |  |                          |       
|                 |  | $                        | 60,546
|                 |  |                          |       



As of December 31, 2004, NSTAR
Electric had executed agreements to divest a number of its purchase power agreements and expects additional divestitures to be executed in 2005. The remaining long-term purchase power agreements are primarily energy only, however, some agreements
have minor capacity cost obligations.



2.
NSTAR Gas Firm Transportation and Storage Agreements



NSTAR Gas purchases
transportation, storage and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that bring gas from major producing regions in the U.S., Gulf of Mexico and Canada to the
final delivery points in the NSTAR Gas service area. NSTAR Gas also utilizes contracts for underground storage facilities to meet its winter peaking demands.



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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 nearly 8.0 billion cubic feet.



NSTAR Gas has various contractual agreements covering the transportation of natural gas and underground natural gas storage facilities, which are recoverable from
customers under the MDTE-approved Cost of Gas Adjustment Clause. These contracts expire at various times from 2006 to 2014. NSTAR Gas firm contract demand charges associated with firm pipeline transportation and storage capacity contracts in
2004, 2003 and 2002 were approximately $48.4 million, $50.5 million and $51.8 million and, respectively. NSTAR Gas firm contract demand charges at current rates under these contracts for the years after 2004 are as follows:



|                 |  |                             |        
|---------------- |  | --------------------------- | -------
|(in thousands)   |  | Firm ContractDemand Charges
|2005             |  | $                           | 48,035 
|2006             |  |                             | 45,418 
|2007             |  |                             | 35,728 
|2008             |  |                             | 35,284 
|2009             |  |                             | 33,938 
|Years thereafter |  |                             | 92,372 
|                 |  |                             |        
|                 |  | $                           | 290,775
|                 |  |                             |        



Note P. Other Utility Matters



Sale of Property



On April 7, 2004, Boston Edison completed the sale of a parcel of land in the City of
Newton, Massachusetts for $15.1 million; the net proceeds from the sale were used to reduce Boston Edisons transition charge. The sale and the regulatory treatment of the proceeds were approved by the MDTE.



Service Quality Indicators



Service quality indicators are established performance benchmarks for certain identified
measures of service quality relating to customer service and billing performance, customer satisfaction, and reliability and safety performance for all Massachusetts utilities. NSTAR Electric and NSTAR Gas are required to report annually to the MDTE
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 March 1, 2004, NSTAR Electric and NSTAR Gas filed their 2003 Service Quality Reports with
the MDTE that demonstrated the Companies achieved levels of reliability and performance; the reports indicate that no penalty was assessable for 2003. The MDTE concurred with NSTARs determination in an order issued in October 2004. NSTAR
monitors its service quality continuously to determine its contingent liability, and if its probable that a liability has been incurred and is estimable, and liability would be accrued. Annually, each NSTAR utility subsidiary makes a service
quality performance filing with the MDTE. Any settlement or rate order that would result in a different liability level from what has been accrued would be adjusted in the period that the MDTE issues an order determining the amount of any such
liability. Recently, the MDTE voted to initiate an investigation into potentially modifying the service quality indicators for all Massachusetts utilities. Until any such order is issued, the current service quality indicators will remain in place.



As of December 31, 2004, NSTAR Electrics and NSTAR Gas 2004
performance has exceeded the applicable established benchmarks and, as such, that no liability has been accrued for 2004.



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Generating Assets Divestiture



On April 8, 2003, Cambridge Electric completed the sale of Blackstone Station to Harvard University (Harvard) for $14.6 million. The net
proceeds ($10.4 million) from the sale were used to reduce Cambridge Electrics transition charge. The sale by Cambridge Electric was approved by the MDTE on March 14, 2003. Also on April 8, 2003, NSTAR Steam Corporation completed the sale
of its Blackstone Station steam assets to Harvard for $3 million. The net impact of these transactions resulted in a pretax gain of $1.3 million. Under terms of an operating agreement, NSTAR Steam continued to manage the day-to-day operations of the
steam plant on this site until April 8, 2004.



Note Q. Commitments and
Contingencies



1. Contractual Commitments



NSTAR also has leases for facilities and equipment. The estimated minimum
rental commitments under non-cancellable capital and operating leases for the years after 2004 are as follows:



|                 |  |   |        
|---------------- |  | - | -------
|(in thousands)   |  |  
|2005             |  | $ | 20,471 
|2006             |  |   | 14,331 
|2007             |  |   | 12,457 
|2008             |  |   | 10,753 
|2009             |  |   | 9,461  
|Years thereafter |  |   | 38,609 
|                 |  |   |        
|                 |  | $ | 106,082
|                 |  |   |        



The total expense for both lease and
transmission agreements was $96.5 million in 2004, $88.2 million in 2003 and $86.6 million in 2002, net of capitalized expenses of $1.5 million in 2004, $1.9 million in 2003 and $2.3 million in 2002.



Total rent expense for all operating leases, except those with terms of a month or less,
amounted to $16.3 million in 2004, $19.9 million in 2003 and $9.1 million in 2002.



NSTAR Electric has entered into a short-term power purchase agreement to meet its entire default service supply obligation, other than to large customers, for the period January 1, 2005 through June 30, 2005 and for 50% of its obligation,
other than to large customers, for the second-half of 2005. NSTAR Electric has entered into a short-term power purchase agreement to meet its entire default service supply obligation for large customers through March 2005. A Request for Proposals
will be issued quarterly in 2005 for the remainder of the obligation for large customers and semi-annually for non-large customers in accordance with MDTE requirements. NSTAR Electric entered into agreements ranging in length from three to
twelve-months effective January 1, 2004 through December 31, 2004 with suppliers to provide full default service energy and ancillary service requirements at contract rates approved by the MDTE. NSTAR Electric is currently recovering payments it is
making to suppliers from its customers and has financial and performance assurances and financial guarantees in place with those suppliers to protect NSTAR Electric from risk in the unlikely event any of its suppliers encounter financial
difficulties or fail to maintain an investment grade credit rating. In connection with certain of these agreements, should, in the unlikely event, an individual NSTAR Electric distribution company receive a credit rating below investment grade, that
company potentially could be required to obtain certain financial commitments, including but not limited to, letters of credit. Refer to Note O, Contracts for the Purchase of Energy for a further discussion.



In the first quarter of 2005, NSTAR expects to begin construction on a 345kV transmission
line that would connect Stoughton, Massachusetts, a southern suburb of Boston, to South Boston. This transmission line is expected to assure continued reliability of electric service and improve power import capacity in the Northeast



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Massachusetts area. This project is expected to be placed in service during the summer of 2006. The cost of the project is expected to be shared by all of
New England and will be recovered by NSTAR through wholesale and retail transmission rates. As of December 31, 2004, NSTAR has contractual commitments of approximately $6 million related to this project.



2. Electric Equity Investments and Joint Ownership Interest



NSTAR 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 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, 2004, NSTARs portion of these guarantees amounted to $9.5 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 their best efforts obligations pursuant to the Equity
Funding Agreement dated June 1, 1985, as amended, for NEH and NHH, in 2004, NEH repurchased a total of 275,000 of its outstanding shares from all equity holders and NHH repurchased a total of 1,500 outstanding shares from all equity holders. Through
December 31, 2004, NSTAR Electrics reduction of its equity ownership resulting from NEH buy-back of 39,785 shares and NHH buy-back of 217 shares was approximately $1,017,000.



NSTAR Electric collectively has an equity ownership of 14% in Connecticut Yankee Atomic Power Company (CYAPC), 14% in Yankee Atomic Electric
Company (YAEC), and 4% in Maine Yankee Atomic Power Company, (collectively, the Yankee Companies). Periodically, NSTAR obtains estimates from the management of the Yankee Companies on the cost of decommissioning the Connecticut Yankee
nuclear unit (CY), the Yankee Atomic nuclear unit (YA), and the Maine Yankee nuclear unit (MY). These nuclear units are completely shut down and are currently conducting decommissioning activities.



Based on estimates from the Yankee Companies management as of December 31, 2004, the
total remaining cost for decommissioning each nuclear unit is approximately as follows: $630 million for CY, $119 million for YA and $292 million for MY. Of these amounts, NSTAR Electric is obligated to pay $88.2 million towards the decommissioning
of CY, $16.7 million toward YA, and $11.7 million toward MY. These estimates are recorded in the accompanying Consolidated Balance Sheets as Power contract liabilities with a corresponding regulatory asset and do not impact the current results of
operations and cash flows. These estimates may be revised from time to time based on information available to the Yankee Companies regarding future costs. The Yankee Companies have received approval from FERC for recovery of these costs and NSTAR
expects any additional increases to these costs to be included in future rate applications with the FERC, with any resulting adjustments being charged to their respective sponsors, including NSTAR Electric. NSTAR Electric would recover its share of
any allowed increases from customers through the transition charge.



The
various decommissioning trusts for which NSTAR or it subsidiaries are responsible through their equity ownership are established pursuant to Federal regulations. The investment of decommissioning funds that have been established, are managed in
accordance with these federal guidelines, state jurisdictions and with the applicable Internal Revenue Service requirements. Some of the requirements state that these investments be managed independently by a prudent fund manager and that funds are
to be invested in conservative, minimum risk investment securities. Any gains or losses are anticipated to be refunded to or collected from customers, respectively.



CYs estimated decommissioning costs increased significantly in 2003 and the increase reflects the fact that CY is now self-performing
all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel). In July 2004, CY filed with FERC for recovery of these increased costs. In August 2004, FERC
issued an order accepting the new rates, beginning in February 2005, subject to refund.



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CY is currently in litigation with Bechtel over the termination of its decommissioning contract. Additionally, Bechtel
filed a complaint against CY asserting several claims as well as wrongful termination. Bechtel sought to garnish the decommissioning trust and related payments. In October 2004, Bechtel and CY entered into a stipulation under which Bechtel
relinquished its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CYs real property in Connecticut with a book value of $7.9 million and the escrowing of portions of the
sponsors periodic payments, up to a total of $41.7 million, all of which the sponsors, which include NSTAR Electric, are scheduled to pay to CY through June 30, 2007. This stipulation is subject to approval of the Court and would not be
implemented until the Court found that such assets were subject to attachment. CY intends to contest the ability of Bechtel to attach these assets. Discovery is underway and a trial has been scheduled for May 2006.



3. Financial and Performance Guarantees



On a limited basis, NSTAR and certain of its subsidiaries may enter into agreements
providing financial assurance to third parties. Such agreements include letters of credit, surety bonds, and other guarantees.



At December 31, 2004, outstanding guarantees totaled $30.3 million as follows:



|                  |  |   |       
|----------------- |  | - | ------
|(in thousands)    |  |  
|Letters of Credit |  | $ | 5,560 
|Surety Bonds      |  |   | 15,281
|Other Guarantees  |  |   | 9,500 
|                  |  |   |       
|Total Guarantees  |  | $ | 30,341
|                  |  |   |       



The $5.6 million letter of credit is
for the benefit of a third party, as trustee in connection with the 6.924% Notes of one of NSTARs subsidiaries. The letter of credit is available if the subsidiary has insufficient funds to pay the debt service requirements. As of December 31,
2004, there have been no amounts drawn under this letter of credit.



As of
December 31, 2004, certain of NSTARs subsidiaries have purchased a total of $0.6 million of performance surety bonds for the purpose of obtaining licenses, permits and rights-of-way in various municipalities. In addition, NSTAR and certain of
its subsidiaries have purchased approximately $14.7 million in workers compensation self-insurer bonds. These bonds support the guarantee by NSTAR and certain of its subsidiaries to the Commonwealth of Massachusetts required as part of the
Companys workers compensation self-insurance program.



NSTAR and
its subsidiaries have also issued $9.5 million of residual value guarantees related to its equity interest in the Hydro-Quebec transmission companies.



Management believes the likelihood NSTAR would be required to perform or otherwise incur any significant losses associated with any of these guarantees is remote.



4. Environmental Matters



As of December 31, 2004, NSTARs subsidiaries are involved in four 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 sometimes uncertainties associated with total remediation costs due to the final selection of the specific cleanup technology and the particular characteristics of the different sites. Estimates
of approximately $0.5 million and $0.7 million are included as liabilities in the accompanying Consolidated Balance Sheets at December 31, 2004 and 2003, respectively.



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In addition to the MCP sites, NSTAR subsidiaries also face possible liability as a result of involvement in 15
multi-party disposal sites or third party claims associated with contamination remediation. NSTAR generally expects to have only a small percentage of the total potential liability for these sites. Estimates of approximately $3.4 million are
included as liabilities in the accompanying Consolidated Balance Sheets at December 31, 2004 and 2003.



The MCP and multi-party disposal site amounts have not been reduced by any potential rate recovery treatment of these costs or any potential recovery from NSTARs insurance carriers. Prospectively, should NSTAR
be allowed to collect these specific costs from customers, it would record an offsetting regulatory asset and record a credit to operating expenses equal to previously expensed costs.



NSTAR Gas is participating in the assessment or remediation of five 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, 2004 and 2003, NSTAR has recorded a liability of approximately $3.8 million and $4.4 million, respectively, as an estimate for site cleanup costs for several MGP sites for which NSTAR Gas was previously cited as a
potentially responsible party. A corresponding regulatory asset has been recorded that reflects the future rate recovery for these costs.



Estimates related to environmental remediation costs are reviewed and adjusted periodically as further investigation and assignment of responsibility occurs and as either
additional sites are identified or NSTARs responsibilities for such sites evolve or are resolved. NSTARs ultimate liability for future environmental remediation costs may vary from these estimates. Based on NSTARs current
assessment of its environmental responsibilities, existing legal requirements and regulatory policies, NSTAR does not believe that these environmental remediation costs will have a material adverse effect on NSTARs consolidated financial
position, results of operations or cash flows for a reporting period.



5. Income Tax Matters



As a result of the RCN
share abandonment in 2003, the Company claimed an ordinary loss on its 2003 tax return for this item. The ordinary loss tax treatment results in the Company realizing the benefits represented by the tax asset recorded on its books that resulted from
the previous write-down of this asset for financial reporting purposes. The requirement for a tax valuation allowance, therefore, no longer exists. The Company has reversed this reserve as of December 31, 2003.



The Company believes it more likely than not that it is entitled to an ordinary loss
deduction. The Company expects the IRS to review this transaction and it is reasonably possible that the IRS will disagree. In accordance with the Companys tax policy as it relates to uncertain tax positions, the Company has established a loss
contingency reserve of approximately $44 million at December 31, 2003. This amount represents the tax impact to the Company should the ordinary loss ultimately be recharacterized to a capital loss. This reserve is recorded as part of Deferred
credits - other on the accompanying Consolidated Balance Sheets.



If the
Companys position is not upheld, the Company may be required to make future cash expenditures that may impact NSTARs consolidated results of operations and cash flows in a future period.



6. Regulatory and Legal Proceedings



a. Regulatory proceedings



On December 21, 2004, the FERC issued an order approving Boston Edisons October 2004
request for Boston Edison to modify its Open Access Transmission Tariff. Effective January 1, 2005, Boston Edison is allowed to include 50 percent of construction work in progress in its rate base for transmission projects by including this



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amount in its local network service transmission rate formula, rather than capitalizing Allowance for Funds Used During Construction (AFUDC) charges on the
entire construction expense balance. The order is subject to Boston Edison filing annual reports of its long-term transmission plan.



In December 2004, NSTAR Electric filed proposed transition rate adjustments for 2005, including a preliminary reconciliation of transition, transmission, standard offer
and default service costs and revenues through 2004. The MDTE subsequently approved tariffs for each retail electric subsidiary effective January 1, 2005. The filings are to be updated in February 2005 to reflect final 2004 costs and revenues which
are subject to final reconciliation.



On February 1, 2005, ISO-NE began
operating as an RTO. As a result, NSTAR has given notice to the RTO and other interested parties of its intent to file for proposed changes to its OATT. This change is expected to provide for consistent application of the OATT among all NSTAR
Electric companies. The 2004 OATT and the related revenue have been based on this proposed change. If successful, NSTAR Electric expects to include the impact in its 2005 billing rates.



Effective January 1, 2005, NSTAR Electrics Standard Offer Service Fuel Adjustment (SOSFA) rates for each of Boston Edison, ComElectric
and Cambridge were modified to a level of 1.564 cents per kilowatt-hour with the approval of the MDTE.



Effective October 1, 2004, Boston Edisons SOSFA rate was modified to 1.223 cents per kilowatt-hour from zero upon approval by the MDTE. The MDTE has allowed companies to adjust prices to reduce deferred cost
balances that arise due to rapidly changing market costs for the oil and natural gas used to generate electricity and the SOSFA is designed to collect the costs of fuel that companies incur for purchasing electricity from their suppliers to serve
their standard offer service customers. Effective September 1, 2003, the Boston Edison SOSFA was reduced to zero while the ComElectric and Cambridge Electric SOSFAs were increased to 1.424 cents per kilowatt-hour until January 1, 2004 when they were
reduced to 1.223 cents per kilowatt-hour. These changes followed an increase in this rate adjustment from zero to 0.902 cents per kilowatt-hour that was effective May 1, 2003 for all three NSTAR Electric companies. The SOSFA was at zero from April
1, 2002 through April 30, 2003 for all three NSTAR Electric companies. The MDTE has ruled that these fuel index adjustments are excluded from the 15% rate reduction requirement under the Restructuring Act.



In December 2003, NSTAR Electric filed proposed transition rate adjustments for 2004,
including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2003. The MDTE subsequently approved tariffs for each retail electric subsidiary effective January 1, 2004. The filings
were updated in February 2004 to include final costs and revenues for 2003.



On
December 1, 2003, NSTAR Electric and NSTAR Gas filed their annual reconciliation report on their pension and PBOP rate adjustment mechanism. Hearings were held during 2004. NSTAR anticipates an order to the first quarter of 2005. NSTAR cannot
predict the overall timing and result of this order on its financial position or results of operations.



b. Other Legal Matters



In the normal course of its business, NSTAR and its subsidiaries are involved in certain legal matters, including civil litigations. Management is unable to fully
determine a range of reasonably possible court-ordered damages, settlement amounts, and related litigation costs (legal liabilities) that would be in excess of amounts accrued and amounts covered by insurance. Based on the information
currently available, NSTAR does not believe that it is probable that any such legal liabilities will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal liabilities that may result
from changes in circumstances could have a material impact on its results of operations, cash flows and financial condition for a reporting period.



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Report of Independent Registered Public Accounting Firm



To Shareholders and Trustees of NSTAR:



We have completed an integrated audit of NSTARs 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004
and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.



Consolidated financial statements and financial statement schedules



In our opinion, the consolidated financial statements listed in the index appearing under
Item 15(a)1 present fairly, in all material respects, the financial position of NSTAR and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended
December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)2 present fairly, in all
material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Companys management.
Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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.



Internal control
over financial reporting



Also, in our opinion, managements
assessment, included in Managements Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria
established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion,
the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Companys
management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on managements
assessment and on the effectiveness of the Companys internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit
of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating managements assessment, testing and evaluating the design and operating effectiveness of internal
control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.



82



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A companys internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those
policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management
and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial
statements.



Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.



PricewaterhouseCoopers LLP



|                                       
|---------------------------------------
|                                       
|/s/ PRICEWATERHOUSECOOPERS LLP         
|                                       
|Boston, Massachusetts February 18,
2005



83



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##### Table of Contents

|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.



|Item 9A. | Controls and Procedures
|-------- | -----------------------



Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures



Under the supervision and with the participation of our management, including our principal executive officer and principal financial
officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act). Based on this evaluation, our principal
executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this annual report.



Managements Report on Internal Control Over Financial Reporting



Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in
the Exchange Act Rules 13a-15(f). A system of internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles.



Under
the supervision and with the participation of management, including the principal executive officer and the principal financial officer, NSTAR management has evaluated the effectiveness of its internal control over financial reporting as of December
31, 2004 based on the criteria established in a report entitled Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, NSTAR management has evaluated
and concluded that NSTARs internal control over financial reporting was effective as of December 31, 2004.



Managements assessment of the effectiveness of NSTARs internal control over financial reporting as of December 31, 2004 has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm that audited NSTARs consolidated financial statements included herewith in the Form 10-K.



|Item 9B. | Other Information
|-------- | -----------------



None



Part III



The information called for by Part III (Items 10(a), 11, 12, and 14) will
be included in NSTARs 2005 Proxy Statement (as specified below) to be filed in connection with the Annual Meeting of Shareholders to be held on April 28, 2005 and is incorporated herein by reference. Such Proxy Statement will be filed with the
Securities and Exchange Commission on or about March 25, 2005.



84



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|Item 10. | Trustees and Executive Officers of the Registrant
|-------- | -------------------------------------------------



(a) Identification of Trustees



The information required by this Item is incorporated herein by reference to the sections included in the Companys 2005 Proxy Statement entitled Information
about the NSTAR Board, Nominees and Incumbent Trustees.



The information
required by this Item with regard to NSTARs Corporate Governance Guidelines is incorporated herein by reference to the section included in the Companys 2005 Proxy Statement entitled Governance of the Company.



The information required by the Item with regard to compliance with Section 16(a) of the
Securities Exchange Act of 1934 is incorporated herein by reference to the section included in the Companys 2005 Proxy Statement entitled Section 16(a) Beneficial Ownership Reporting Compliance.



Audit, Finance and Risk Management Committee Financial Expert



The NSTAR Board of Trustees has made a determination that Mr. Daniel Dennis, CPA, an
independent trustee and a member of NSTARs Audit, Finance and Risk Management Committee, is an audit committee financial expert as that term is defined in the SECs regulations.



(b) Identification of Officers



Information required by this item is included in Item 4A of this Form 10-K.



|Item 11. | Executive Compensation
|-------- | ----------------------



The information required by this Item is incorporated herein by reference to the section included in the Companys 2005 Proxy Statement entitled Executive
Compensation.



|Item 12. | Security Ownership of Certain Beneficial Owners and Management
|-------- | --------------------------------------------------------------



The information required by this item is incorporated herein by reference to the section included in the Companys 2005 Proxy Statement entitled Trustee
Compensation, Common Share Ownership by Trustees and Executive Officers, and Change in Control Agreements.



|Item 13. | Certain Relationships and Related Transactions
|-------- | ----------------------------------------------



The information required by this Item is not applicable to NSTAR.



|Item 14. | Principal Accountant Fees and Services
|-------- | --------------------------------------



The information required by this Item is incorporated herein by reference to the section included in the Companys 2005 Proxy Statement entitled 2003 -2004
Audit and Related Fees.



With regard to the Audit, Finance and Risk
Management Committees policy to pre-approve all audit and non-audit services by the Companys independent public accountants, the information required by this Item is incorporated herein by reference to the section included in the
Companys 2005 Proxy Statement entitled Audit, Finance and Risk Management Committee report.



85



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Part IV



|Item 15. | Exhibits and Financial Statement Schedules
|-------- | ------------------------------------------



(a) The following documents are filed as part of this Form 10-K:



|1. | Financial Statements:
|-- | ---------------------



|                                                                                                     |  |     
|---------------------------------------------------------------------------------------------------- |  | ----
|                                                                                                     |  | Page
|Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002               |  | 45  
|                                                                                                     | 
|Consolidated Statements of Comprehensive Income for the years ended December 31, 2004, 2003 and 2002 |  | 46  
|                                                                                                     | 
|Consolidated Statements of Retained Earnings for the years ended December 31, 2004, 2003 and 2002    |  | 46  
|                                                                                                     | 
|Consolidated Balance Sheets as of December 31, 2004 and 2003                                         |  | 47  
|                                                                                                     | 
|Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002           |  | 48  
|                                                                                                     | 
|Notes to Consolidated Financial Statements                                                           |  | 49  
|                                                                                                     | 
|Selected Consolidated Quarterly Financial Data (Unaudited)                                           |  | 13  
|                                                                                                     | 
|Report of Independent Registered Public Accounting Firm                                              |  | 82  
|                                                                                                     | 
|2.      Financial Statement Schedules:                                                               |  |     
|                                                                                                     | 
|Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2004, 2003 and 2002 |  | 90  



|3. | Exhibits:
|-- | ---------



Refer to the exhibits listing beginning below.



Incorporated herein by reference unless designated otherwise:



NSTAR (Registrant)



|          |  |                                                                                                                                                                                                                                                   
|--------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit 3 |  | Articles of Incorporation and By-Laws                                                                                                                                                                                                             
|          | 
|3.1       |  | Declaration of Trust of NSTAR (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 (Annex E to the Joint Proxy Statement/Prospectus, which forms part of the Registration Statement on Form S-4 of NSTAR (No. 333-78285))                                                                                            
|          | 
|Exhibit 4 |  | Instruments Defining the Rights of Security Holders, Including Indentures                                                                                                                                                                         
|          | 
|4.1       |  | Indenture dated as of January 12, 2000 between NSTAR and Bank One Trust Company N.A. (Exhibit 4.1 to NSTAR Registration Statement on Form S-3, File No. 333-94735)                                                                                
|          | 
|4.2       |  | Votes of the Board of Trustees of NSTAR, dated January 27, 2000, supplementing the Indenture dated as of January 12, 2000 between NSTAR and Bank One Trust Company N. A. (NSTAR Form 10-K for
the year ended December 31, 2002, File No. 1-14768) 
|          | 
|4.3       |  | Votes of the Board of Trustees of NSTAR, dated September 28, 2000 supplementing the Indenture dated as of January 12, 2000 between NSTAR and Bank One Trust Company N. A. (NSTAR Form 10-K for
the year ended December 31, 2002, File No. 1-14768)



86



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|           |  |                                                                                                                                                                                                                                                                                     
|---------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|           | 
|4.4        |  | Boston Edison Company Revolving Credit Agreement dated November 15, 2002 (Boston Edison Form 10-Q for the quarter ended March 31, 2003, File No. 1-2301)                                                                                                                            
|           | 
|           |  | Management agrees to furnish to the Securities and Exchange Commission, upon request, a copy of any other agreements or instruments of NSTAR and its subsidiaries defining the rights of
holders of any long-term debt whose authorization does not exceed 10% of total assets.     
|           | 
|Exhibit 10 |  | Material Contracts                                                                                                                                                                                                                                                                  
|           | 
|10.1       |  | NSTAR Excess Benefit Plan, effective August 25, 1999 (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768)                                                                                                                                                     
|           | 
|10.2       |  | NSTAR Supplemental Executive Retirement Plan, effective August 25, 1999 (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768)                                                                                                                                  
|           | 
|10.3       |  | Special Supplemental Executive Retirement Agreement between Boston Edison Company and Thomas J. May dated March 13, 1999, regarding Key Executive Benefit Plan and Supplemental Executive
Retirement Plan (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768)
|           | 
|10.4       |  | Executive Retirement Plan Agreement between NSTAR and Werner J. Schweiger dated as of February 25, 2002, regarding Supplemental Executive Retirement Plan (filed herewith)                                                                                                          
|           | 
|10.5       |  | Amended and Restated Change in Control Agreement between NSTAR and Thomas J. May dated October 23, 2003 (NSTAR Form 10-K for the year ended December 31, 2003, File No.
1-14768)                                                                                                    
|           | 
|10.6       |  | 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)                                                                                                                                    
|           | 
|10.7       |  | 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)                                                                                               
|           | 
|10.7.1     |  | NSTAR 1997 Share Incentive Plan, as amended January 24, 2002 (NSTAR Form 10-K for the year ended December 31, 2002, File No. 1-14768)                                                                                                                                               
|           | 
|10.8       |  | Amended and Restated Change in Control Agreement between James J. Judge and NSTAR, November 1, 2001. (NSTAR Form 10-K for the year ended December 31, 2001, File No. 1-14768)                                                                                                       
|           | 
|10.9       |  | NSTAR Trustees 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)                                                                                                             
|           | 
|10.10      |  | Master Trust Agreement between NSTAR and State Street Bank and Trust Company (Rabbi Trust), effective August 25, 1999 (NSTAR Form 10-Q for the quarter ended September 30, 2000, File No.
1-14768)                                                                                  
|           | 
|10.11      |  | Amended and Restated Change in Control Agreement between Douglas S. Horan and NSTAR dated November 1, 2001 (NSTAR Form 10-K for the year ended December 31, 2001, File No.
1-14768)                                                                                                 
|           | 
|10.12      |  | Amended and Restated Change in Control Agreement between Joseph R. Nolan, Jr. and NSTAR dated November 1, 2001 (NSTAR Form 10-K for the year ended December 31, 2001, File No.
1-14768)                                                                                             
|           | 
|10.13      |  | Amended and Restated Change in Control Agreement between Werner J. Schweiger and NSTAR dated March 1, 2002 (NSTAR Form 10-K for the year ended December 31, 2001, File No.
1-14768)                                                                                                 



87



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|                            |  |                                                                                                                                                                                                                                                       
|--------------------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                            | 
|10.14                       |  | Amended and Restated NSTAR Annual Incentive Plan as of January 1, 2003 (filed herewith)                                                                                                                                                               
|                            | 
|Exhibit 21                  |  | Subsidiaries of the Registrant                                                                                                                                                                                                                        
|                            | 
|21.1                        |  | (filed herewith)                                                                                                                                                                                                                                      
|                            | 
|Exhibit 23                  |  | Consent of Independent Accountants                                                                                                                                                                                                                    
|                            | 
|23.1                        |  | (filed herewith)                                                                                                                                                                                                                                      
|                            | 
|Exhibit 31                  |  | Rule 13a - 15/15d-15(e) Certifications (filed herewith)                                                                                                                                                                                               
|                            | 
|31.1                        |  | Certification Statement of Chief Executive Officer of NSTAR pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                                                                                                                 
|                            | 
|31.2                        |  | Certification Statement of Chief Financial Officer of NSTAR pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                                                                                                                 
|                            | 
|Exhibit 32                  |  | Section 1350 Certifications (filed herewith)                                                                                                                                                                                                          
|                            | 
|32.1                        |  | Certification Statement of Chief Executive Officer of NSTAR pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                                                                                                                 
|                            | 
|32.2                        |  | Certification Statement of Chief Financial Officer of NSTAR pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                                                                                                                 
|                            | 
|Exhibit 99                  |  | Additional Exhibits                                                                                                                                                                                                                                   
|                            | 
|99.1                        |  | Annual Reports on Form 11-K for certain employee savings plans for the years ended December 31, 2003, 2002, 2001 and 2000, as dated June 25, 2004, June 30, 2003, June 28, 2002 and June
29, 2001, 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 dated April 19, 1977, as amended January 22, 1987, January 28, 1988, May 24, 1988, and November 22, 1989 (Form 10-Q for the quarter ended June 30, 1990, File No.
1-2301)                                                
|                            | 
|Exhibit 4                   |  | Instruments Defining the Rights of Security Holders, Including Indentures                                                                                                                                                                             
|                            | 
|4.1                         |  | Indenture between Boston Edison Company and the Bank of New York (as successor to Bank of Montreal Trust Company)(Form 10-Q for the quarter ended September 30, 1988, File No.
1-2301)                                                                
|                            | 
|4.11                        |  | Votes of the Pricing Committee of the Board of Directors of Boston Edison Company taken March 5, 1993 re 6.80% Debentures due March 15, 2003 and 7.80% debentures due March 15, 2023 (Form 10-K
for the year ended December 31, 1992, File No. 1-2301)
|                            | 
|4.12                        |  | Votes of the Pricing Committee of the Board of Directors of Boston Edison Company taken May 10, 1995 re 7.80% debentures due May 15, 2010 (Form 10-K for the year ended December 31, 1995, File
No. 1-2301)                                           



88



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|                                            |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|------------------------------------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                                            | 
|4.13                                        |  | Votes of the Board of Directors of Boston Edison Company taken October 8, 2002 re $500 million aggregate principal amount of unsecured debentures ($400 million, 4.875% due in 2012 and $100
million, Floating rate due in 2005)(Form 8-K dated October 11, 2002, File No. 1-2301)                                                                                                                                                                                             
|                                            | 
|Exhibit 10                                  |  | Material Contracts                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|                                            | 
|10.11                                       |  | Boston Edison Company and Entergy Nuclear Generation Company Purchase and Sale Agreement dated November 18, 1998 (Form 10-K for the year ended December 31, 1999, File No.
1-2301)                                                                                                                                                                                                                                                                                             
|                                            | 
|10.12                                       |  | Boston Edison Company Restructuring Settlement Agreement dated July 1997 (Form 10-K for the year ended December 31, 1997, File No. 1-2301)                                                                                                                                                                                                                                                                                                                                     
|                                           
|Commonwealth Energy System and Subsidiaries
|                                            | 
|Exhibit 10                                  |  | Power Contracts                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|                                            | 
|10.2.1                                      |  | New England Power Pool Agreement (NEPOOL) dated September 1, 1971 as amended through August 1, 1977, between NEGEA Service Corporation, as agent for Cambridge Electric, Canal, ComElectric;
Boston Edison Company and various other electric utilities operating in New England together with amendments dated August 15, 1978, January 31, 1979 and February 1, 1980. (Exhibit 5(c)13 to New England Gas and Electric Associations Form S-16
(April 1980), File No. 2-64731)
|                                            | 
|10.2.1.1                                    |  | Thirteenth Amendment to 10.2.1 as amended September 1, 1981 (refiled as Exhibit 3 to the Parents 1991 Form 10-K, File No. 1-7316)                                                                                                                                                                                                                                                                                                                                             
|                                            | 
|10.2.1.2                                    |  | Fourteenth through Twentieth Amendments to 10.2.1 as amended December 1, 1981, June 1, 1982, June 15, 1983, October 1, 1983, August 1, 1985, August 15, 1985 and September 1, 1985,
respectively (Exhibit 4 to the CES Form 10-Q (September 1985), File No. 1-7316)                                                                                                                                                                                                            
|                                            | 
|10.2.1.3                                    |  | Twenty-first Amendment to 10.2.1 as amended to January 1, 1986 (Exhibit 1 to the CES Form 10-Q (March 1986), File No. 1-7316)                                                                                                                                                                                                                                                                                                                                                  
|                                            | 
|10.2.1.4                                    |  | Twenty-second Amendment to 10.2.1 as amended to September 1, 1986 (Exhibit 1 to the CES Form 10-Q (September 1986), File No. 1-7316)                                                                                                                                                                                                                                                                                                                                           
|                                            | 
|10.2.1.5                                    |  | Twenty-third Amendment to 10.2.1 as amended to April 30, 1987 (Exhibit 1 to the CES Form 10-Q (June 1987), File No. 1-7316)                                                                                                                                                                                                                                                                                                                                                    
|                                            | 
|10.2.1.6                                    |  | Twenty-fourth Amendment to 10.2.1 as amended March 1, 1988 (Exhibit 1 to the CES Form 10-Q (March 1989), File No. 1-7316)                                                                                                                                                                                                                                                                                                                                                      
|                                            | 
|10.2.1.7                                    |  | Twenty-fifth Amendment to 10.2.1 as amended to May 1, 1988 (Exhibit 1 to the CES Form 10-Q (March 1988), File No. 1-7316)                                                                                                                                                                                                                                                                                                                                                      
|                                            | 
|10.2.1.8                                    |  | Twenty-sixth Agreement to 10.2.1 as amended March 15, 1989 (Exhibit 1 to the CES Form 10-Q (March 1989), File No. 1-7316)                                                                                                                                                                                                                                                                                                                                                      
|                                            | 
|10.2.1.9                                    |  | Twenty-seventh Agreement to 10.2.1 as amended October 1, 1990 (Exhibit 3 to the CES 1990 Form 10-K, File No. 1-7316).                                                                                                                                                                                                                                                                                                                                                          
|                                            | 
|10.2.1.10                                   |  | Twenty-eighth Agreement to 10.2.1 as amended September 15, 1992 (Exhibit 1 to the CES Form 10-Q (September 1994), File No. 1-7316)                                                                                                                                                                                                                                                                                                                                             
|                                            | 
|10.2.1.11                                   |  | Twenty-ninth Agreement to 10.2.1 as amended May 1, 1993 (Exhibit 2 to the CES Form 10-Q (September 1994), File No. 1-7316)                                                                                                                                                                                                                                                                                                                                                     



89



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SCHEDULE II



VALUATION AND QUALIFYING ACCOUNTS



FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 and 2002



(Dollars in Thousands)



|                                |  |                            |        |                                |   |                                |  |   |                      |  |   |        |  |   |       
|------------------------------- |  | -------------------------- | ------ | ------------------------------ | - | ------------------------------ |  | - | -------------------- |  | - | ------ |  | - | ------
|                                |  |                            |        | Additions                      |   | Deductions AccountsWritten Off |  |  
|Description                     |  | Balance atBeginningof Year |        | ProvisionsCharged toOperations |   | Recoveries                     |  |   | BalanceAt Endof Year
|Allowance for Doubtful Accounts |  |                            |        |                                |   |                                |  |   |                      |  |   |        |  |   |       
|Year Ended December 31, 2004    |  | $                          | 23,424 |                                | $ | 24,569                         |  | $ | 7,371                |  | $ | 33,560 |  | $ | 21,804
|Year Ended December 31, 2003    |  | $                          | 24,379 |                                | $ | 20,509                         |  | $ | 5,949                |  | $ | 27,413 |  | $ | 23,424
|Year Ended December 31, 2002    |  | $                          | 29,763 |                                | $ | 19,688                         |  | $ | 6,690                |  | $ | 31,762 |  | $ | 24,379
|                                |  |                            |        |                                |  
|Tax Valuation Allowance         |  |                            |        |                                |   |                                |  |   |                      |  |   |        |  |   |       
|Year Ended December 31, 2004    |  | $                          |       |                                | $ |                               |  | $ |                     |  | $ |       |  | $ |      
|Year Ended December 31, 2003    |  | $                          | 52,897 |                                | $ |                               |  | $ |                     |  | $ | 52,897 |  | $ |      
|Year Ended December 31, 2002    |  | $                          | 64,499 |                                | $ | 15,384                         |  | $ |                     |  | $ | 26,986 |  | $ | 52,897



90



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|          |  |       |  |                  
|--------- |  | ----- |  | -----------------
|FORM 10-K |  | NSTAR |  | DECEMBER 31, 2004



SIGNATURES



Pursuant to the
requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



| |  |                        |  |  |  |     |  |                                                        
| |  | ---------------------- |  |  |  | --- |  | -------------------------------------------------------
| |  |                        |  | 
| |  |                        |  |  |  |     |  | NSTAR                                                  
| |  |                        |  |  |  |     |  | (Registrant)                                           
| |  |                        |  | 
| |  | Date February 18, 2005 |  |  |  | By: |  | /s/    ROBERT J. WEAFER,
JR.                           
| |  |                        |  |  |  |     |  | Robert J. Weafer, Jr.                                  
| |  |                        |  |  |  |     |  | Vice President, Controller and Chief Accounting Officer



Pursuant to the
requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated as of the 18th day of February 2005.



|                                                  |  |                                                             
|------------------------------------------------- |  | ------------------------------------------------------------
|Signature                                         |  | Title                                                       
|                                                  | 
|/s/    THOMAS J. MAYThomas J. May                 |  | Chairman, President, Chief Executive Officer and Trustee    
|                                                  | 
|/s/    JAMES J. JUDGEJames J. Judge               |  | Senior Vice President, Treasurer and Chief Financial Officer
|                                                  | 
|/s/    G.L. COUNTRYMANGary L. Countryman          |  | Trustee                                                     
|                                                  | 
|/s/    DANIEL DENNISDaniel Dennis                 |  | Trustee                                                     
|                                                  | 
|/s/    THOMAS G. DIGNAN,
JR.Thomas G. Dignan,
Jr. |  | Trustee                                                     
|                                                  | 
|/s/    CHARLES K.
GIFFORDCharles K.
Gifford       |  | Trustee                                                     
|                                                  | 
|/s/    MATINA S.
HORNERMatina S.
Horner           |  | Trustee                                                     
|                                                  | 
|/s/    FRANKLIN M.
HUNDLEYFranklin M.
Hundley     |  | Trustee                                                     
|                                                  | 
|/s/    PAUL A. LA
CAMERAPaul A. La
Camera         |  | Trustee                                                     
|                                                  | 
|/s/    SHERRY H.
PENNEYSherry H.
Penney           |  | Trustee                                                     
|                                                  | 
|/s/    WILLIAM C. VAN
FAASENWilliam C. Van
Faasen |  | Trustee                                                     
|                                                  | 
|/s/    G. L. WILSONGerald L. Wilson               |  | Trustee                                                     



91