NSTAR/MA - 10-K Annual Report

NSTAR

Form 10-K Annual Report - December 31, 2003

	Part I	Page

Item 1.	Business	2
Item 2.	Properties	10
Item 3.	Legal Proceedings	11
Item 4.	Submission of Matters to a Vote of Security Holders	11
Item 4A.	Executive Officers of the Registrant	11

	Part II

Item 5.	Market for the Registrant’s Common Equity and Related Stockholder Matters	13
Item 6.	Selected Consolidated Financial Data	14
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 8.	Financial Statements and Supplementary Financial Information	49
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	91
Item 9A.	Controls and Procedures	91

	Part III

Item 10.	Trustees and Executive Officers of the Registrant	91
Item 11.	Executive Compensation	92
Item 12.	Security Ownership of Certain Beneficial Owners and Management	92
Item 13.	Certain Relationships and Related Transactions	92
Item 14.	Principal Accountant Fees and Services	92

	Part IV

Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	93



Signatures		100



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. In May 2003, the Board amended the charter of each of these committees. The Board also has a standing Executive Committee. In 2003, the Board 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 codes which 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 an energy delivery company engaged primarily in the transmission and distribution of energy. NSTAR serves approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric customers in 81 communities and 0.3 million gas customers in 51 communities. NSTAR is a public utility holding company generally exempt from the provisions of the Public Utility Holding Company Act of 1935. NSTAR’s retail utility subsidiaries are Boston Edison Company (Boston Edison), Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas). Its wholesale electric subsidiary is Canal Electric Company (Canal). NSTAR’s three retail electric companies operate under the brand name “NSTAR Electric.” Reference in this report to “NSTAR” shall mean the registrant NSTAR or one or more of its subsidiaries as the context requires. Reference in this report to “NSTAR Electric” shall mean each of Boston Edison, ComElectric and Cambridge Electric. NSTAR’s non-utility, unregulated operations include district energy operations (Advanced Energy Systems, Inc. and NSTAR Steam Corporation), telecommunications operations (NSTAR Communications, Inc. (NSTAR Com)) and a liquefied natural gas service company (Hopkinton LNG Corp.). Utility operations accounted for approximately 96% of consolidated operating revenues in 2003, 2002 and 2001.

NSTAR was created in 1999 in connection with the merger of BEC Energy (BEC) and Commonwealth Energy System (COM/Energy). An integral part of the merger involved the rate plan of the NSTAR Electric subsidiaries. Significant elements of the rate plan included a distribution rate freeze through August 2003, recovery of the acquisition premium (goodwill) over 40 years and recovery of transaction and integration costs (costs to achieve) over 10 years. Refer to the “Rate and Regulatory Proceedings” section in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information.

In 2002, Canal sold its 3.52% ownership interest in the Seabrook Nuclear Power Station and in April 2003 Cambridge Electric sold Blackstone Station, its lone remaining generating asset. These transactions finalized the divestiture of all of NSTAR’s regulated generating assets. Refer to the “Generating Assets Divestiture” section in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information.

(b) Financial Information about Industry Segments

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

(c) Narrative Description of Business

Principal Products and Services

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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. In 2003, NSTAR Electric served approximately 1.1 million customers.

NSTAR Electric’s operating revenues and energy sales percentages by customer class for the years 2003, 2002 and 2001 consisted of the following:

	Revenues ($)			Energy Sales (MWH)

Retail:	2003	2002	2001	2003	2002	2001
Commercial	54%	52%	51%	59%	56%	55%
Residential	38%	37%	33%	31%	29%	28%
Industrial and other	7%	8%	9%	9%	10%	11%
Wholesale and contract sales	1%	3%	7%	1%	5%	6%

Retail Electric Rates

Unbundled delivery rates are established by the Massachusetts Department of Telecommunications and Energy (MDTE) and are composed of distribution charges including 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), a transition charge (to collect costs for previously held investments in generating plants and current costs related to above market power contracts), a transmission charge (to collect the cost of moving the electricity over high voltage lines from a generating plant to substations located within NSTAR’s service area), an energy conservation charge (to collect costs for demand-side management programs) and a renewable energy charge (to collect the cost to support the development and promotion of renewable energy projects). Beginning in 2004, NSTAR’s rate was increased to reflect the carrying charge on the average net prepaid pension and postretirement benefit obligations other than pension (PBOP) balances and to recover a portion of the deferred pension and PBOP balances for 2003. Refer to the 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. Currently, standard offer service is scheduled to be available to eligible customers through February 2005 at prices approved by the MDTE. The delivery rates and the standard offer service are set at levels so as to guarantee mandatory overall rate reductions required by the Massachusetts Electric Restructuring Act of 1997 (Restructuring Act). Currently, new retail customers in the NSTAR Electric service territories and other customers who are no longer eligible for standard offer service and have not chosen to receive service from a competitive supplier are provided default service. 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. NSTAR anticipates that upon the expiration of standard officer service, effective March 1, 2005, all customers will be eligible for default service. However, Massachusetts’ officials are considering new deregulation legislation to be effective after March 1, 2005. NSTAR cannot predict or anticipate the outcome of this process or its impact on NSTAR or its customers. As of December 31, 2003 and 2002, customers of NSTAR Electric had approximately 26% and 27%, respectively, of their load requirements provided by competitive suppliers.

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Sources and Availability of Electric Power Supply

NSTAR Electric expects to continue to make periodic market solicitations for default service and standard offer power supply consistent with provisions of the Restructuring Act and MDTE orders. NSTAR Electric has contracted with third party suppliers to provide 100% of its standard offer supply obligation through December 31, 2004. In connection with this arrangement, NSTAR Electric has assigned its long-term power purchase agreements to one supplier through December 31, 2004. These long-term power purchase agreements are expected to supply approximately 80%-85% of its standard offer service obligations for 2004 and have been assigned to this supplier. NSTAR Electric is fully recovering its payments to suppliers through MDTE approved rates billed to customers. NSTAR Electric’s existing portfolio of long-term power purchase contracts supplied a significant amount of its standard offer (including wholesale) energy requirements in 2003. Also during 2003 and 2002, NSTAR Electric entered into an agreement whereby all of its energy supply resource entitlements were assigned to an independent energy supplier, following which NSTAR Electric repurchased its energy resource needs from this independent energy supplier for NSTAR Electric’s ultimate sale to standard offer customers.

NSTAR Electric’s load for 2003 reached a peak demand of 4,299 megawatts (MW) on August 22, which was 2.6% less than the all-time peak demand level of 4,415 MW established in 2002.

Standard Market Design (SMD)

Prior to March 1, 2003, Independent System Operator - New England (ISO-NE) dispatched generating units based on the lowest operating costs of available generation and transmission. Under this structure, generators were required to provide ISO-NE with market prices at which they sell short-term energy supply. For each participant actively involved in the power market, the imbalance in energy provided by a participant and the energy consumed by such participant in each hour is settled at a single real-time clearing hourly price for such power. Pursuant to orders issued by the Federal Energy Regulatory Commission (FERC) in September and December of 2002, these markets were further restructured into SMD, which began on March 1, 2003. SMD provides an additional market in which wholesale power costs can be hedged a day in advance through binding financial commitments. Also, under SMD, wholesale power clearing prices vary by location, called load zones, with prices in load zones with less efficient generation being higher than in load zones with more efficient generation while transmission constraints prevent the lower cost generation from moving from one load zone to another. NSTAR Electric 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. At times NEMA has higher priced generation than SEMA. As part of SMD, load-serving entities, like NSTAR Electric, were granted proceeds from auction of “financial transmission rights” that is conducted by ISO-NE. NSTAR Electric can either use these proceeds to mitigate costs to customers directly or transfer them to the suppliers of its energy resource needs to reduce the cost to customers.

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Further developments in the movement towards SMD will occur in 2004 with the introduction of a capacity requirement within load zones by load serving entities (LSE), like NSTAR Electric. The current market structure allows capacity, located within all of New England, to count towards a LSE’s obligation. Since the New England market as a whole is currently in a surplus position, capacity trades at a relatively low price. Pursuant to FERC orders, ISO-NE is developing a new structure that will require LSE to provide a portion of their capacity needs within the zone where load is served. This will likely increase the price of power to NSTAR’s customers. These market rules are in development and must be approved by the FERC, currently scheduled for mid-2004. Until these rules are finalized and approved, NSTAR cannot anticipate the impact these changes will have on NSTAR Electric and its customers.

Regional Transmission Organization (RTO)

On October 31, 2003, the ISO-NE, responsible for the day-to-day operations of New England’s bulk generation and transmission systems, together with the utility companies that own transmission facilities in New England, filed a proposal with FERC creating a RTO in compliance with FERC directives and pronouncements. It is anticipated that FERC will act on this proposal by March 2004.

An RTO is intended to be an independent entity, without a financial interest in the region’s marketplace, that would have operating authority over the New England transmission grid and have the responsibility to make impartial decisions on the development and implementation of market rules. Under the ISO’s current proposal, the ISO-NE will be transformed into an RTO through a change of name and governance structure, designed to ensure independence from market participants. The new RTO will enter into a series of contractual arrangements that will define its functions and responsibilities, including a Transmission Operating Agreement, which will govern the relationship between the owners of transmission facilities, such as NSTAR (“Transmission Owners” (TO)) and the RTO, as the operator of the New England transmission grid. Separate agreements will govern the operation of the spot power and related markets, and merchant transmission facilities. Notwithstanding broad agreement between the ISO-NE and TOs on the allocation of their respective rights and responsibilities, there remain certain issues, particularly regarding the authority to make tariff filings and liability and indemnification obligations of the parties, which have not been fully resolved and may require FERC adjudication. While the RTO proposal has the support of the ISO-NE and the TOs, the New England Power Pool declined to support the proposal by a substantial margin. The Chairman of the MDTE has voiced support for the concept of an RTO, while the Massachusetts Attorney General has voiced skepticism about the benefits of the proposed RTO. The FERC effort encouraging the voluntary formation of an RTO is itself under attack nationally from opposition groups, primarily in the South and West. NSTAR generally supports the RTO proposal, which delineates the roles and responsibilities of TOs and the RTO in grid operation and potentially may increase the return earned on its investment in transmission-related assets. Management cannot estimate the impact of this proposal on the Company at this time.

NSTAR Gas

NSTAR Gas’ operating revenues and energy sales percentages by customer class for the years 2003, 2002 and 2001, consisted of the following:

	Revenues ($)			Energy Sales (therms)

Gas Sales and Transportation:	2003	2002	2001	2003	2002	2001
Residential	61%	64%	58%	47%	42%	43%
Commercial	25%	21%	27%	33%	34%	34%
Industrial and other	10%	9%	10%	17%	19%	18%
Off-System and contract sales	4%	6%	5%	3%	5%	5%

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NSTAR Gas distributes natural gas to approximately 0.3 million customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles and having an aggregate population of 1.2 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.

Natural Gas Industry Restructuring and Rates

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

In addition to delivery service rates, NSTAR Gas’ tariffs include a seasonal Cost of Gas Adjustment Clause (CGAC) and a Local Distribution Adjustment Clause (LDAC). The CGAC provides for the recovery of all gas supply costs from firm sales customers 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’s rate was increased to reflect the carrying charge on the average net prepaid pension and PBOP balances and to recover a portion of the deferred pension and PBOP balances for 2003. 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 supplier to all customers of local gas distribution companies (LDCs) such as NSTAR Gas. The regulations established a five-year transition period and a three-year review of market conditions to determine whether the 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.

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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).

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

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

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

Franchises

Through their charters, which are unlimited in time, NSTAR Electric and NSTAR Gas have the right to engage in the business of 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 or gas distribution pipelines are obtained from municipal and other state authorities which, in granting these locations, act as agents for the state. In some cases the actions of these authorities are subject to appeal to the MDTE. The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature. Under Massachusetts law, no other entity may provide electric or gas delivery service to retail customers within NSTAR’s

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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 and Boston. Telecommunications services are provided through NSTAR Com, which installs, owns, operates and maintains a wholesale transport network for other telecommunications service providers in the metropolitan Boston area to deliver voice, video, data and internet services to customers. Liquefied natural gas service is provided by Hopkinton LNG Corp.

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 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.

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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Capital Expenditures and Financings

The most recent estimates of capital expenditures and long-term debt maturities for the years 2004 through 2008 are as follows:

	2004	2005	2006	2007	2008
(in thousands)
Capital expenditures*	$309,000	$313,000	$325,000	$256,000	$255,000
Long-term debt	$230,033	$177,562	$248,024	$83,218	$85,629


*	Includes expenditures related to NSTAR’s 345kv transmission project. This project is subject to regulatory approvals. Refer to “Liquidity and Capital Resources” section of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further discussion.

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.”

Net plant expenditures in 2003 were approximately $308 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 as well as for new combustion turbines of NSTAR’s AES facility.

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

Seasonal Nature of Business

NSTAR Electric kilowatt-hour sales and revenues are typically higher in the winter and summer than in the spring and fall as sales tend to vary with weather conditions. NSTAR Gas’ sales are positively impacted by colder weather because a substantial portion of its customer base uses natural gas for space heating purposes. Refer to the “Selected Consolidated Quarterly Financial Data” section in Item 6, “Selected Consolidated Financial Data” for specific financial information by quarter for 2003 and 2002.

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 was created to operate in this marketplace by combining the resources of its utility subsidiaries activities in the transmission and distribution of energy.

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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, 2003, NSTAR had approximately 3,200 employees, including approximately 2,400, or 75%, who are represented by three units covered by separate collective bargaining contracts.

Local 369 of the Utility Workers Union of America, AFL-CIO, represents approximately 2,000 employees with a contract that expires on May 15, 2005. Approximately 260 employees, represented by Local 12004, United Steelworkers of America, AFL-CIO, have a contract that expires on March 31, 2006. Approximately 70 employees of Advanced Energy Systems’ MATEP subsidiary are represented by Local 877, the International Union of Operating Engineers, AFL-CIO, with 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, 2003, 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 1,127,000 active customer meters.

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

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.

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NSTAR Gas’ principal natural gas properties consist of distribution mains, services and meters necessary to maintain reliable service to customers. At December 31, 2003, the gas system included approximately 2,950 miles of gas distribution lines, approximately 177,500 services and approximately 274,100 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 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 high pressure steam lines to customers in Cambridge and Boston.

Item 3. Legal Proceedings

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 liability will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal liabilities that may result from changes in estimates could have a material impact on its results of operations for a reporting period.

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

There were no matters submitted to a vote of security holders during the fourth quarter of 2003.

Item 4A. Executive Officers of Registrant

Identification of Executive Officers

Name of Officer	Position and Business Experience	Age at December 31, 2003

Thomas J. May	Chairman, President (since 2002), Chief Executive Officer and a Trustee (since 1999); formerly Chairman, President and Chief Executive Officer and a Trustee (1998-1999), BEC Energy; Director, FleetBoston Financial; Liberty Mutual Holding Company Inc.; and New England Business Services, Inc.	56

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Name of Officer	Position and Business Experience		Age at December 31, 2003

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); Senior Vice President - Strategy and Law and General Counsel, BEC Energy (1998-1999).	54

James J. Judge	Senior Vice President, Treasurer and Chief Financial Officer (since 2000); formerly Senior Vice President and Chief Financial Officer (1999-2000); Senior Vice President - Corporate Services and Treasurer, BEC Energy (1998-1999).	47

Timothy R. Manning	Senior Vice President - Human Resources (since 2002); formerly Vice President Human Resources (2001); Director of Employee and Labor Relations (1999-2001), Director of Human Resources, Boston Edison Company (1998-1999).	52

Joseph R. Nolan, Jr.	Senior Vice President - Customer Care and Corporate Relations (since 2002); formerly Senior Vice President - Corporate Relations (2000-2002); Vice President of Government Affairs (1999-2000); Director of Regulatory Relations, BEC Energy (1998-1999).	40

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).	44

Eugene J. Zimon	Senior Vice President - Information Technology (since 2001); formerly Vice President, Business Development for Utilities, Oracle Corporation (2000-2001); Vice President, Information Services, Boston Gas Company (1996-2000).	55

Robert J. Weafer, Jr.	Vice President, Controller and Chief Accounting Officer (since 1999); formerly Vice President, Controller and Chief Accounting Officer, BEC Energy (1998-1999).	56

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PART II

Item 5. Market for the Registrant’s Common Equity and Related Stockholder Matters

(a) Market Information

NSTAR’s common shares are listed on the New York and Boston Stock Exchanges. NSTAR’s closing market price at December 31, 2003 was $48.50 per share.

The high and low market values per common share as reported by the New York Stock Exchange composite transaction reporting system for each of the quarters in 2003 and 2002 were as follows:

	2003		2002
	High	Low	High	Low
First quarter	$46.12	$38.67	$46.00	$42.30
Second quarter	$48.00	$39.78	$48.20	$43.66
Third quarter	$48.34	$43.63	$45.17	$34.00
Fourth quarter	$48.96	$45.08	$44.70	$36.90

(b) Holders

As of December 31, 2003, there were 26,701 holders of NSTAR common shares.

Dividends declared per common share for each quarter of 2003 and 2002 were as follows:

	2003	2002
First quarter	$0.54	$0.53
Second quarter	$0.54	$0.53
Third quarter	$0.54	$0.53
Fourth quarter	$0.555	$0.54

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Item 6. Selected Consolidated Financial Data

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

(in thousands, except per share data)
	2003	2002	2001	2000	1999(c)
Operating revenues	$2,914,131	$2,691,573	$3,184,046	$2,692,762	$1,851,427
Net income (loss)(a)	$ 181,574	$ 161,707	$ (2,426)	$ 175,002	$ 140,503
Earnings (loss) per share of common stock:
Basic (a)	$ 3.42	$ 3.05	$ (0.05)	$ 3.19	$ 2.77
Diluted (a)	$ 3.40	$ 3.03	$ (0.05)	$ 3.18	$ 2.76
Total assets	$6,320,660	$6,338,454	$5,328,191	$5,547,715	$5,466,143
Long-term debt (b)	$1,605,381	$1,645,465	$1,377,899	$1,440,431	$ 986,843
Transition property securitization (b)	$ 377,150	$ 445,890	$ 513,904	$ 584,130	$ 646,559
Preferred stock of subsidiary (b)	$ 43,000	$ 43,000	$ 43,000	$ 43,000	$ 92,279
Cash dividends declared per common share	$ 2.175	$ 2.13	$ 2.075	$ 2.015	$ 1.955

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

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

(c)	Due to the application of the purchase method of accounting, the results for 1999 reflect eight months of BEC Energy and four months of NSTAR.

Selected Consolidated Quarterly Financial Data (Unaudited)

(in thousands, except earnings per share)

				Earnings
			Net	Per Basic
	Operating	Operating	Income	Common Share
	Revenues	Income	(a)	(a)(b)

2003
First quarter	$ 763,555	$ 85,477	$ 42,338	$ 0.80
Second quarter	$ 647,910	$ 74,136	$ 39,154	$ 0.74
Third quarter	$ 817,791	$ 103,175	$ 63,662	$ 1.20
Fourth quarter	$ 684,875	$ 73,256	$ 36,420	$ 0.69

2002
First quarter	$ 705,228	$ 76,715	$ 34,304	$ 0.65
Second quarter	$ 593,270	$ 69,061	$ 5,200	$ 0.10
Third quarter	$ 743,284	$ 117,141	$ 73,227	$ 1.38
Fourth quarter	$ 649,791	$ 74,680	$ 48,976	$ 0.92

(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 (RCN) fully offset by the recognition of related tax benefits of $4.5 million.

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	The second quarter of 2002 includes a non-cash, after-tax impairment charge of $27.6 million, or $0.52 per share, related to NSTAR’s investment in RCN common stock.

	The fourth quarter of 2002 includes a net gain of $9.9 million, or $0.19 per share, that reflects the recognition of tax benefits, based on an IRS review of NSTAR’s 1999 and 2000 tax returns, of $19.6 million, or $0.37 per share, related to NSTAR’s investment in RCN offset, in part, by an additional non-cash, after-tax impairment charge of $9.7 million, or $0.18 per share, associated with the RCN investment.

(b)	The sum of the quarters may not equal basic annual earnings per share due to rounding.

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

Overview

NSTAR generates its revenues primarily from the sale of energy, distribution and transmission services to customers and from its unregulated businesses. However, 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 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,”

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“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
-	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 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

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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. Also note that NSTAR provides in the above paragraphs a cautionary discussion of risks and other uncertainties relative to its business. These are factors that could cause its actual results to differ materially from expected and historical performance. Other factors in addition to those listed here could also adversely affect NSTAR. This report also describes material contingencies and critical accounting policies and estimates in this section and in the accompanying Notes to Consolidated Financial Statements, and NSTAR encourages a review of these Notes.

Critical Accounting Policies and Estimates

NSTAR’s discussion and analysis of its financial condition, results of operations and cash flows are based upon the accompanying Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of these Consolidated Financial Statements required management to make estimates and 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. 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. The determination of unbilled revenues requires management to estimate the volume and pricing of electricity and gas delivered to customers prior to actual meter readings.

Revenues related to the sale, transmission and distribution of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters that are read on a systematic basis throughout the month. Meters which are not read during a given month are estimated and trued-up in a future period. At the end of each month, amounts of energy delivered to customers since the date of the last billing date are estimated and the corresponding unbilled revenue is estimated. This unbilled electric revenue is estimated each month based on daily generation volumes (territory load), 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, 2003 and 2002 were $46 million and $47 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

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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 costs that have been deferred because they are probable of future recovery from customers. As of December 31, 2003 and 2002, NSTAR has recorded regulatory assets of $1.9 billion and $2 billion, respectively. This decrease is primarily the result of the collection of regulatory generation-related assets secured by securitization certificates and costs to achieve the 1999 merger from customers and retiree benefit costs as a result of a lower additional minimum liability adjustment. NSTAR continuously reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. NSTAR expects to fully recover these regulatory assets in its rates. If future recovery of costs ceases to be probable, NSTAR would be required to charge these assets to current earnings. However, impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Regulatory assets related to the generation business are recovered through the transition charge.

c. Derivative Instruments - Power Contracts

Typically, the electric power industry contracts to buy and sell electricity under option contracts, which allow the buyer some flexibility in determining when to take electricity and in what quantity to match fluctuating demand. These contracts would normally meet the definition of a derivative requiring mark-to-market accounting. However, because electricity cannot be stored and 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 described in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and Derivative Implementation Group (DIG) Issue No. C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity.”

NSTAR Electric has long-term purchased power agreements that are used primarily to meet its standard offer obligation. The majority of these agreements are above-market but are not reflected on the accompanying Consolidated Balance Sheets as they qualify for the normal purchases and sales exception. However, in Issue C15, the DIG concluded that contracts with a pricing mechanism that are subject to future adjustment based on a generic index that is not specifically related to the contracted service commodity generally would not qualify for the normal purchases and sales exception. NSTAR has six purchased power contracts that contain components with pricing mechanisms that are based on a pricing index, such as the Gross National Product or Consumer Price Index. Although these factors are only applied to certain ancillary pricing components of these agreements, as required by the interpretation of DIG Issue C15, NSTAR began recording these contracts at fair value on its Consolidated Balance Sheets during 2002. As a result, the recognition of a liability for the fair value of the above-market portion of these contracts at December 31, 2003 is approximately $666 million and is reflected as a

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component of Deferred credits - Power contracts on the accompanying Consolidated Balance Sheets.

These contracts are valued using a discounted cash flow model and a 10% discount rate. The market value assumption used was provided by a third party who determines such pricing for the New England power market. Had management used an alternative assumption, the value of these contracts at December 31, 2003 would have changed significantly. A one percent increase or decrease to the discount rate would change the above market value by approximately $30 million from what is presently recorded.

NSTAR Electric recovers all of its electricity supply costs, including the above-market costs from customers. For these six purchased power agreements, the recovery of its above-market costs occurs through 2013 for Boston Edison, through 2017 for ComElectric and through 2011 for Cambridge Electric. These recovery periods coincide with the contractual terms of these purchased power agreements. Therefore, in addition to the liability recorded, NSTAR also recorded a corresponding regulatory asset representing the future recovery of these actual costs. 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 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, earnings on the plans’ assets, the discount rate, the expected long-term rate of return on the plans’ assets and health care cost trends.

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

There were no significant changes to NSTAR’s pension plan benefits in 2003, 2002 and 2001 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 in 2003 to 6.25% from 6.50% in 2002 to reflect market conditions. In addition, NSTAR revised the expected long-term rate of return on its pension plan assets for 2003 to 8.4%, reduced from 9.4% in 2002. These changes will have a significant impact on reported pension costs in future years in accordance with the cost recognition approach of SFAS 87 described above. This impact will be mitigated through NSTAR’s regulatory accounting treatment of pension and PBOP costs. (See further discussion of regulatory accounting treatment below). In determining pension obligation and cost amounts, these assumptions may change from period to period, and such changes could result in material changes to recorded pension and PBOP costs and funding requirements.

NSTAR’s Pension Plan (the Plan) assets, which partially consist of equity investments, were affected by significant declines in the financial markets from 2000 through 2002 despite positive investment performance during 2003. Fluctuations in market returns may result in increased or decreased pension costs in future periods. These conditions impacted the funded status of the Plan at both December 31, 2003 and 2002, and therefore, will also impact pension costs for 2004.

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

(in thousands)
		Impact on
		Projected
		Benefit	Impact on 2003 Cost
Actuarial Assumption	Change in Assumption	Obligation	Increase/(Decrease)

Pension:
Increase in discount rate	50 basis points	$ (48,282)	$ (3,607)
Decrease in discount rate	50 basis points	$ 52,915	$ 3,903
Increase in expected long-term
rate of return on plan assets	50 basis points	NA	$ (3,491)
Decrease in expected long-term
rate of return on plan assets	50 basis points	NA	$ 3,491

Other Postretirement Benefits:
Increase in discount rate	50 basis points	$ (39,673)	$ (2,876)
Decrease in discount rate	50 basis points	$ 44,514	$ 3,173
Increase in expected long-term
rate of return on plan assets	50 basis points	NA	$ (1,115)
Decrease in expected long-term
rate of return on plan assets	50 basis points	NA	$ 1,115
NA-not applicable

NSTAR’s discount rate is based on rates of high quality corporate bonds of appropriate maturities as published by nationally recognized rating agencies and through periodic bond portfolio matching.

In determining the expected long-term rate of return on plan assets, NSTAR considers past performance and economic forecasts for the types of investments held by the Plan. In 2003, NSTAR reduced the expected long-term rate of return on plan assets from 9.4% to 8.4% as a result of the prevailing outlook for equity market returns. This rate is presented net of both administrative expenses and investment expenses, which have averaged approximately 0.6% for both 2003 and 2002. NSTAR pays both types of expenses for the Plan. Reported pension costs increased in 2003 and will likely increase in 2004 and future years as a result of this changed assumption. However, as a result of the MDTE order (the Order) discussed below, this increase will not have an impact on NSTAR’s results of operations.

The unfavorable market conditions from 2000 through 2002 impacted the value of Plan assets. As a result of this negative investment performance and, despite the positive investment performance in 2003, the Plan’s accumulated benefit obligation (ABO) exceeded Plan assets at both December 31, 2003 and 2002. The ABO represents the present value of benefits earned without considering future salary increases. Since the fair value of its Plan assets is less than the ABO, NSTAR is required to record this difference as an additional minimum pension liability on the accompanying Consolidated Balance Sheets.

Under SFAS 87, NSTAR is also required to eliminate its prepaid pension balance. The additional minimum pension liability adjustment is equal to the sum of the minimum pension liability and the prepaid pension that would be recorded, net of taxes, as a non-cash charge to Other Comprehensive Income (OCI) on the accompanying Consolidated Statements of Comprehensive Income. The fair value of Plan assets and the ABO are measured at each year-end balance sheet date. The minimum liability will be adjusted each year to reflect this measurement. At such time that the Plan assets exceed the ABO, the minimum liability would be reversed.

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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, which effectuated a 2002 MDTE Accounting Order, NSTAR is allowed to record a regulatory asset in lieu of taking a charge to OCI for the additional minimum liability requirement for under-funded benefit plans. As of December 31, 2003 and 2002, NSTAR has recorded a regulatory asset of $299 million and $426 million, respectively. The regulatory asset is shown as part of Deferred debits 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 $43 million to the Plan in 2004. NSTAR believes it has adequate access to capital resources to support these contributions.

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 nuclear power plants, NSTAR Electric collectively owns, through its equity investments, 14% of Connecticut Yankee Atomic Power Company (CYAPC), 14% of Yankee Atomic Electric Company (YAEC), and 4% of Maine Yankee Atomic Power Company, (the “Yankee Companies”). Periodically, NSTAR obtains estimates from the management of the Yankee Companies on the cost of decommissioning the Connecticut Yankee nuclear unit (CY), the Yankee Atomic nuclear unit (YA), and the Maine Yankee nuclear unit (MY). These nuclear units are completely shut down and are currently conducting decommissioning activities.

Based on estimates from the Yankee Companies’ management as of December 31, 2003, the total remaining cost for decommissioning each nuclear unit is approximately as follows: $666 million for CY, $181 million for YA and $364 million for MY. Of these amounts, NSTAR Electric is obligated to pay $93.3 million towards the decommissioning of CY, $25.4 million toward YA, and $14.6 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. These estimates may be revised from time to time based on information available to the Yankee Companies regarding future costs.

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

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

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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, cost of removal (negative net salvage) is recognized as a component of depreciation expense in accordance with approved regulatory treatment. Cost of removal was previously included in accumulated deprecation but is currently reflected as a regulatory liability in conjunction with the adoption of SFAS 143. As of December 31, 2003 and 2002, the estimated amount of the cost of removal included in regulatory liabilities was approximately $223 million and $234 million, respectively, based on the 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. Based on current information and assumptions, NSTAR, in the first quarter of 2003, 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 is recorded as part of Depreciation and amortization expense on the accompanying Consolidated Statements of Income.

New Accounting Standards

In April 2003, the FASB issued SFAS No. 149 “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149). SFAS 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. SFAS 149 also amends SFAS 133 for implementation issues raised in relation to the application of the definition of a derivative. SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and its provisions are to be applied prospectively. The adoption of SFAS 149 did not have a material effect on NSTAR’s financial position or results of operations.

In May 2003, the FASB issued SFAS No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (SFAS 150). This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The Statement is intended to improve the accounting for these financial instruments that, under previous guidance, issuers could account for as equity. This Statement requires that these instruments be classified as liabilities on the balance sheet. NSTAR adopted SFAS 150 effective July 1, 2003. NSTAR assessed the requirements of the Statement and has not identified any financial instruments to which SFAS 150 applies. In addition, NSTAR has not entered into, nor modified, any financial instrument since May 31, 2003. As a result, the implementation of this Statement has not had an impact on NSTAR’s financial position or results of operations.

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In June 2003, the Derivatives Implementation Group (DIG), a working group of the FASB, issued DIG No. C20, “Scope Exceptions: Interpretation of the Meaning of ‘Not Clearly and Closely Related’ in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature,” which clarified the interpretation of clearly and closely related contracts that include price adjustments. This interpretation also established transition guidance for those contracts that had previously met the normal purchases and sales exception under previous guidance but may not meet the scope exception under this interpretation. For NSTAR, the effective date of DIG Issue No. C20 was October 1, 2003. NSTAR has assessed the impact of this interpretation on its current derivative contracts and has determined that NSTAR will continue to designate these contracts as derivative financial instruments and will mark-to-market their values at each reporting date.

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities”, as amended and revised in December 2003 (FIN 46R), which addresses the consolidation of variable interest entities (VIE’s) 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. Application of this Interpretation is required for all potential VIE’s that are referred to as special-purpose entities for periods ending after December 15, 2003 and, for all other types of entities that are potential VIE’s that are not referred to as special purpose entities, the consolidation requirements apply for periods ending after March 15, 2004. NSTAR has assessed the impact of FIN 46R and has determined that it does not have any VIE’s for which NSTAR is the primary beneficiary requiring consolidation of the entity as of December 31, 2003. For all other types of entities, NSTAR is still assessing the impact that FIN 46R will have on its consolidated financial position.

NSTAR has a wholly owned special purpose subsidiary, BEC Funding LLC, established to facilitate the sale and administration of $725 million in notes to a special purpose trust created by two Massachusetts state agencies. Historically, NSTAR has consolidated this entity. As part of NSTAR’s assessment of FIN 46R, 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 variable interest entity and should continue to be consolidated by NSTAR. Refer to the section entitled “Sources of Additional Capital and Financial Covenant Requirements” in the section.

Generating Assets Divestiture

a. Seabrook Nuclear Power Station

On November 1, 2002, FPL Group, Inc. purchased an 88% ownership interest in the Seabrook Nuclear Power Station, including Canal’s 3.52% ownership interest, for $799.4 million, net of closing adjustments. FPL Group assumed responsibility for the ultimate decommissioning of the facility and received the Seabrook decommissioning funds of approximately $226.9 million at the closing. Canal’s portion of the sale proceeds amounted to $31.9 million, of which $3.5 million was paid into the decommissioning trust as a final top-off and $1.3 million was used for other transaction costs. The net proceeds of $27.1 million were less than Canal’s remaining investment in Seabrook. The difference of approximately $16.2 million was included as a component of Cambridge Electric’s and ComElectric’s transition cost recovery and was collected from ComElectric’s and Cambridge Electric’s customers in 2003 through the transition charge. As part of this sale, all purchased power agreements were terminated. The Seabrook sale did not have a material impact on NSTAR’s current results of operations. The future impact of the sale will not have a material effect on NSTAR’s results of operations, cash flow or financial position.

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b. 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 will continue to manage the day-to-day operations of the steam plant on this site for one year after the sale.

Rate and Regulatory Proceedings

a. Goodwill and Costs to Achieve

The merger that created NSTAR was accounted for using the purchase method of accounting. In accordance with the MDTE’s approval of the 1999 merger rate plan, the premium (Goodwill) associated with the acquisition was approximately $490 million, while the original estimate of transaction and integration costs to achieve the merger was $111 million. The merger premium is reflected on the accompanying Consolidated Balance Sheets as Goodwill. This premium will continue to be amortized over 40 years and amounts to approximately $12.2 million annually, while the costs to achieve (CTA) are being amortized over 10 years. CTA are the costs incurred to execute the merger including the employee costs for a voluntary severance program, costs of financial advisers, legal costs, and other transaction and systems integration costs. CTA was being amortized at an annual rate of $11.1 million based on the original rate plan, as approved by the MDTE through the rate freeze period. 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 2003 was approximately $12.9 million, an increase of $1.8 million over 2002. NSTAR will reconcile the actual CTA costs incurred with the original estimate in a future rate proceeding. This reconciliation will include a final accounting of the deductibility for income tax purposes of each component of CTA. The total CTA is approximately $143 million. This increase from the original estimate is partially mitigated by the fact that the portion of CTA that is not deductible for income tax purposes is approximately $20 million lower than the original estimate. NSTAR anticipates that these incremental costs are probable of recovery in future rates. The CTA and Goodwill amounts were filed and approved as part of the rate plan.

b. 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 February 28, 2003, NSTAR Electric and NSTAR Gas filed their 2002 Service Quality Reports with the MDTE that reflected significant improvements in reliability and performance; the reports indicate that no penalty was assessed for 2002. The MDTE concurred with NSTAR’s determination in an order issued on September 30, 2003. NSTAR monitors its service quality continuously to determine its contingent liability, and if it were determined that a liability has been incurred and is estimable, an appropriate 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 an agreement is reached with the MDTE.

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As of December 31, 2003, NSTAR Electric’s and NSTAR Gas’ 2003 performance has exceeded the applicable established benchmarks such that no liability has been accrued for 2003.

c. 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. Currently, standard offer service is scheduled to be available to eligible customers through February 2005 at prices approved by the MDTE. The delivery rates and the standard offer service are set at levels so as to guarantee mandatory overall rate reductions required by the Massachusetts Electric Restructuring Act of 1997 (Restructuring Act). Currently, new retail customers in the NSTAR Electric service territories and other customers who are no longer eligible for standard offer service and have not chosen to receive service from a competitive supplier are provided default service. 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. NSTAR anticipates that upon the expiration of standard officer service, effective March 1, 2005, all customers will be eligible for default service. However, Massachusetts officials are considering new deregulation legislation to be effective after March 1, 2005. NSTAR cannot predict or anticipate the outcome of this process or its impact on NSTAR or its customers. As of December 31, 2003 and 2002, customers of NSTAR Electric had approximately 26% and 27%, respectively, of their load requirements provided by competitive suppliers.

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 reflect final 2003 costs and revenues which are subject to final reconciliation.

On November 6, 2003, Boston Edison received approval of a Settlement Agreement with the Massachusetts Attorney General (AG) from the MDTE resolving issues in Boston Edison’s reconciliation of costs and revenues for the year 2002. This settlement had minimal impact to Boston Edison’s results of operation.

Effective September 1, 2003, Boston Edison’s, ComElectric’s and Cambridge Electric’s Standard Offer Service Fuel Adjustment (SOSFA) rates were modified 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. The Boston Edison SOSFA was reduced to zero while the ComElectric and Cambridge Electric SOSFAs were increased to 1.424 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.

Effective January 1, 2004, NSTAR Electric’s SOSFA rates were modified again with the approval of the MDTE. The Boston Edison SOSFA remained at zero per kilowatt-hour. The ComElectric and Cambridge Electric SOSFA were reduced to 1.223 cents per kilowatt-hour.

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subsidiary effective January 1, 2003. The filings were updated in February 2003 to include final costs and revenues for 2002.

On November 14, 2002, Boston Edison received approval of a Settlement Agreement with the AG from the MDTE resolving issues in Boston Edison’s reconciliation of costs and revenues for the year 2001. Among other issues, the Settlement Agreement included an adjustment for the reconciliation of costs related to securitization and efforts to mitigate costs incurred in relation to a purchased power agreement with Hydro Quebec. As a result of this Settlement Agreement with the AG, Boston Edison recognized approximately $11.4 million in additional transition charge revenues in 2002. This benefit was significantly offset by several other regulatory true-up adjustments.

d. Standard Market Design (SMD)

Prior to March 1, 2003, Independent System Operator - New England (ISO-NE) dispatched generating units based on the lowest operating costs of available generation and transmission. Under this structure, generators were required to provide ISO-NE with market prices at which they sell short-term energy supply. For each participant actively involved in the power market, the imbalance in energy provided by a participant and the energy consumed by such participant in each hour is settled at a single real-time clearing hourly price for such power. Pursuant to orders issued by the FERC in September and December of 2002, these markets were further restructured into SMD, which began on March 1, 2003. SMD provides an additional market in which wholesale power costs can be hedged a day in advance through binding financial commitments. Also, under SMD, wholesale power clearing prices vary by location, called load zones, with prices in load zones with less efficient generation being higher than in load zones with more efficient generation while transmission constraints prevent the lower cost generation from moving from one load zone to another. NSTAR Electric 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. At times NEMA has higher priced generation 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 can either use these proceeds to mitigate costs to customers directly or transfer them to the suppliers of its energy resource needs to reduce the cost to customers.

e. Regional Transmission Organization (RTO)

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An RTO is intended to be an independent entity, without a financial interest in the region’s marketplace, that would have operating authority over the New England transmission grid and have the responsibility to make impartial decisions on the development and implementation of market rules. Under the ISO’s current proposal, the ISO-NE will be transformed into an RTO through a change of name and governance structure, designed to ensure independence from market participants. The new RTO will enter into a series of contractual arrangements that will define its functions and responsibilities, including a Transmission Operating Agreement, which will govern the relationship between the owners of transmission facilities, such as NSTAR (“Transmission Owners” (TO)) and the RTO, as the operator of the New England transmission grid. Separate agreements will govern the operation of the spot power and related markets, and merchant transmission facilities. Notwithstanding broad agreement between the ISO-NE and TOs on the allocation of their respective rights and responsibilities, there remain certain issues, particularly regarding the authority to make tariff filings and liability and indemnification obligations of the parties, which have not been fully resolved and may require FERC adjudication. While the RTO proposal has the support of the ISO-NE and the TOs, the New England Power Pool recently declined to support the proposal by a substantial margin. The Chairman of the MDTE has voiced support for the concept of an RTO, while the Massachusetts Attorney General has voiced skepticism about the benefits of the proposed RTO. The FERC effort encouraging the voluntary formation of an RTO is itself under attack nationally from opposition groups, primarily in the South and West. NSTAR generally supports the RTO proposal, which delineates the roles and responsibilities of TOs and the RTO in grid operation and potentially may increase the return earned on its investment in transmission-related assets. Management cannot estimate the impact of this proposal on the Company at this time.

f. Natural Gas Industry Restructuring and Rates

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

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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

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 Issues

a. 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 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.

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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 will claim 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 to zero at December 31, 2003. However, the Company expects the IRS to review this transaction and it is reasonably possible that the IRS will disagree. As a result, the Company established a loss contingency reserve of approximately $44 million at December 31, 2003.

b. Tax Gain on Generating Assets

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

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 COM/Energy’s 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.

Results of Operations

The following section of MD&A compares the results of operations for each of the three fiscal years ended December 31, 2003, 2002 and 2001 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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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, effective September 1, 2003, as a result of a MDTE order, 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, increased contributions to NSTAR’s pension and PBOP plans and an increase in energy costs. 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 no penalties would be incurred by NSTAR 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

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	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

The 3.0% increase in retail MWH sales in 2003 reflects, by customer sectors, an improvement of 6.1% in residential and 2.7% in commercial offset somewhat by the continued sales decline of 5.8% in the industrial sector. The 14.7% increase in firm gas sales in 2003 primarily reflects an improvement of 15% in the residential sector.

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 retail 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. Unit sales of electricity in 2004 are expected to grow at approximately 1.5% to 2%. Firm gas sales are expected to remain flat or decrease by up to 2%.

			Normal
			30-Year
	2003	2002	Average


Heating degree-days	6,263	5,658	5,944
Percentage change from prior year	10.7%	-%
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.

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Operating revenues

Operating revenues for 2003 increased 8.3% 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		1,453.5		1,381.5		72.0			5.2

Total retail		2,314.2		2,192.4		121.8			5.6
Wholesale		21.5		64.2		(42.7	)		(66.5	)

Total electric revenues		2,335.7		2,256.6		79.1			3.5
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	$	2,914.1	$	2,691.6	$	222.5			8.3

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 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

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municipal wholesale electric contract will expire resulting in a further 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.

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 $1,328.7 million for 2003 compared to $1,233.2 million in 2002, an increase of $95.5 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.

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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. Refer to “Rate and Regulatory Proceedings” in this MD&A for further discussion. This increase was partially offset by the reduction in operations and maintenance expense in connection with 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.

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.

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.

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. Excluding 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.

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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 $11.6 million in 2003 compared to $26.9 million in 2002, a decrease of $15.3 million, or 57%. 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 1.29% 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.

2002 compared to 2001

Earnings and Operations Overview

Earnings (loss) per common share were as follows:

	Years ended December 31,

		2002	2001	% Change
Basic		$3.05	$(0.05)	NM
Diluted		$3.03	$(0.05)	NM
NM-not meaningful

Net income was $161.7 million, or $3.05 and $3.03 per basic and diluted common share, respectively, for 2002. Earnings for 2002 include non-cash, after-tax charges of $17.7 million, or $0.33 per basic and diluted common share related to NSTAR’s investment in RCN that is further discussed below. For 2001, NSTAR reported a loss of $2.4 million of $0.05 per basic and diluted common share. Results for 2001 were $171.5 million, or $3.23 per basic and $3.22 per diluted common share, and excludes a non-cash, after-tax charge of $173.9 million, or $3.28 per basic share, related to NSTAR’s investment in RCN.

Absent RCN charges in both years, 2002 earnings increased by $7.9 million ($0.15 per share), or 4.6%, primarily due to increased MWH and firm gas sales and transportation and favorable adjustments related to regulatory orders, lower preferred dividend requirements and interest

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savings offset by higher operations and maintenance expenses. Operations and maintenance reflects higher pension and other postretirement benefits expenses and increased maintenance on the electric system in connection with the System Improvement Program. Cash flows from operations increased by over $261 million due to the higher level of earnings, improved accounts receivable collections, lower regulatory cost deferrals, and income tax payments. Other positive factors during 2002 included lower bad debt expense of $4.5 million and a $3.9 million deferred tax benefit resulting from an adjustment to NSTAR’s tax valuation allowance. NSTAR’s return on equity was 12.6% despite the downturn in the economic environment. NSTAR and subsidiaries maintained their credit ratings with all rating agencies. In addition, NSTAR increased its common dividend rate by $0.04 or 1.9% per share to $2.16 on an annual basis.

Capital spending in 2002 significantly exceeded the prior year’s level due to an increase in the allocation of critical capital resources to improve electric system reliability and customer service. As a result of this spending, key electric and gas operating performance results were greatly improved in 2002 over those of 2001. Electric customer outrage hours were reduced by 35% and the length of those outages was reduced by 27%. These dramatic improvements were accomplished during record-breaking summer heat and an unprecedented demand for electricity. Also contributing to this increase was additional capital spending related to NSTAR’s non-regulated subsidiaries, primarily Advanced Energy System’s generation expansion project.

On June 19, 2002, NSTAR received an additional 7.5 million shares from the third and final exchange of its investment in the RCN joint venture pursuant to an amended Joint Venture Agreement. The market value of RCN common shares continued to decline during 2002 and did not close above NSTAR’s previously adjusted carrying value of $3.75 per share since November 27, 2001. As a result, NSTAR recognized impairment charges totaling $37.3 million, reducing the carrying value of its 11.6 million RCN shares to $0.53 per share as of December 31, 2002. These charges were offset by the recognition of $19.6 million in tax benefits relating to joint venture operating losses. Combined, the impairment charges and tax benefits amounted to $17.7 million, or $0.33 per share in 2002. Similarly, in 2001, due to a significant decrease in the market value of RCN common shares, NSTAR recorded a non-cash, after-tax charge of $173.9 million. Management determined that these declines in market value were “other-than-temporary” in accordance with SFAS 115, “Accounting for Certain Investments in Debt and Equity Securities.”

Operating revenues

Operating revenues for 2002 decreased 15% from 2001 as follows:

(in thousands)
Retail electric revenues	$	(394,834)
Wholesale electric revenues		(22,702)
Gas sales revenues		(65,203)
Other revenues		(9,734)

Decrease in operating revenues	$	(492,473)

The decrease in operating revenues was significantly impacted by the decline in standard offer and default service rates charged to customers beginning in January 2002 that reflected lower purchased power and gas costs.

Retail electric revenues were $2,094.8 million in 2002 compared to $2,489.7 million in 2001, a decrease of $394.9 million, or 16%. The change in retail revenues includes the significantly lower cost of purchased energy supply (discussed below) that contributed to the lower rates implemented in January, April and July 2002 for standard offer and default services. Components of the total decrease in retail revenues includes lower revenues attributable to

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standard offer and default services of $263.8 million and $163.9 million, respectively, lower revenue related to demand-side management and renewable energy programs of $8.1 million due to the reconciliation of program costs, an increase in incentive adjustments and the timing of program expenditures. Transition revenues increased by $36.1 million due to higher rates for transition cost recovery offset by an $8 million decline in mitigation incentive revenues that are allowed for successfully lowering transition charges. Mitigation incentive revenues will continue to decrease over the transition period extending over time from 2009 through 2026. Transmission revenues increased by $4.8 million primarily as a result of rate increases and the absence in 2002 of a $6.7 million reduction in 2001 revenues that reflected an MDTE-approved transmission reconciliation filing. The change in NSTAR’s retail revenues related to standard offer, default services and demand-side management and renewable energy are reconciled to the costs incurred.

The 1.2% increase in retail MWH sales in 2002 reflects, by customer sectors, an improvement of 2% in residential and 1.8% in commercial offset somewhat by the continued sales decline of 5.5% in the industrial sector. The overall increase in sales is attributable to the warmer summer period, as compared to the prior year. 2002 was the tenth warmest year in 132 years. However, the economic downturn continued to have a negative impact on sales as indicated by the high Boston office vacancy rate. Business spending continued to be depressed as firms were reluctant to commit to increased employment and expansion of office space. The unemployment rate in Boston was approximately 4.4% through December 2002 as compared to approximately 3% in the same period in 2001. NSTAR Electric’s sales to residential and commercial customers were approximately 29% and 56%, respectively, of its total retail sales mix for 2002 and provided 37% and 52% of total revenues, respectively. Industrial sales declined due primarily to a slowdown in economic conditions that led to reduced production or facility closings. The industrial and other retail sales sector comprised approximately 10% of NSTAR’s energy sales and 8% of distribution revenue.

The first quarter of 2002 was significantly warmer than the same period in 2001, followed by slightly below normal temperatures for the second quarter, above-normal temperatures in the third quarter and colder than prior year and normal conditions in the fourth quarter of 2002. Below is comparative information on heating and cooling degree-days for 2002 and 2001 and the number of degree-days in a “normal” year as represented by a 30-year average.

			Normal
			30-Year
	2002	2001	Average


Heating degree-days	5,658	5,644	5,942
Percentage change from prior year	-%	(8.3)%
Percentage change from 30-year average	(4.8)%	(5.1)%

Cooling degree-days
Percentage change from prior year	972	822	777
Percentage change from 30-year average	18.2%	39.8%
	25.1%	5.8%

The heating degree-days experienced during 2002 were virtually the same level with heating degree-days in 2001. However, in the first quarter of 2002, heating degree-days totaled 2,522, a decline of 16% from the prior year of 3,007 and 15% below a normal level of 2,975. Heating degree-days for the fourth quarter were 2,172, an increase of 28% as compared to 2001 and 8% greater than normal. The warmer than normal conditions in early 2002 significantly impacted earnings for gas operations due to the relatively short winter period when there is potential heating demand.

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The higher cooling degree-days experienced during 2002 positively impacted electric distribution revenues. The above normal cooling degree-days impacted air conditioning usage of our customers and resulted in higher electric distribution revenues than would otherwise have been recorded during a more moderate summer period.

Electric wholesale revenues were $64.2 million in 2002 compared to $86.9 million in 2001, a decrease of $22.7 million, or 26%. This decrease in wholesale revenues reflects the expiration of two municipal power supply contracts on May 31, 2002, and another municipal contract on October 31, 2002, and a decline in rates due to the lower cost of purchased power. Amounts collected from wholesale customers are credited to retail customers through the transition charge. Therefore, the expiration of these contracts has no impact on results of operations

Gas sales revenues were $323.2 million in 2002 compared to $388.4 million in 2001, a decrease of $65.2 million, or 17%. The decrease in revenues is primarily attributable to a 26% decline in the cost of gas from suppliers compared to the same period in 2001, slightly offset by a 0.6% increase in firm energy sales.

Other revenues were $209.4 million in 2002 compared to $219.1 million in 2001, a decrease of $9.7 million, or 4%. This decrease primarily reflects lower revenues from non-utility operations due to lower steam sales that reflect warmer weather during the early part of 2002, lower billing rates, and the loss of a large customer, partially offset by higher chilled water revenues due to the warmer summer period and higher demand rates.

Operating expenses

Purchased power costs were $1,233.2 million in 2002 compared to $1,665.7 million in 2001, a decrease of $432.5 million, or 26%. The decrease in expense reflects a decline in prices of natural gas and oil and a 22% decrease in wholesale sales due to the expiration of three municipal power supply contracts. Partially offsetting the impact of these decreases was a 1.2% increase in retail electric sales and an increase in transmission costs. Included in 2002 and 2001 was $3.8 million and $208.1 million, respectively, that related to the recognition of previously deferred standard offer and default service supply costs resulting from the current period collection of previously deferred costs. NSTAR adjusts its electric rates to collect the costs related to energy supply from customers on a reconciling basis. Due to the rate adjustment mechanism, a change in the amount of energy supply expense does not have an impact on earnings.

The cost of gas sold, representing NSTAR Gas’ supply expense, was $176.5 million in 2002 compared to $239.5 million in 2001, a decrease of $63 million, or 26%, reflecting the lower cost of gas supply and the significant reduction in sales due to milder weather conditions in the first quarter of 2002. These expenses are also reconciled to the current level of revenues collected.

Operations and maintenance expense was $431.7 million in 2002 compared to $417.1 million in 2001, an increase of $14.6 million, or 4%. This increase primarily reflects incremental expenditures incurred relating to improvements to NSTAR’s electric delivery system that were substantially completed as of September 30, 2002, an increase of approximately $17.7 million and $5.6 million in pension-related and postretirement benefits expense (net of amounts capitalized), respectively, resulting primarily from a downturn in the equity market and a $2.3 million loss incurred that related to an insurance settlement adjustment. The increase in pension costs and other postretirement benefit costs continued through 2003, as a result of the declines in the equity markets over the past three years. These factors were somewhat offset by the absence of $3.7 million in storm costs incurred in the first quarter of 2001 and a decline in bad debt expense of $4.5 million

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Depreciation and amortization expense was $239.2 million in 2002 compared to $231 million in 2001, an increase of $8.2 million, or 4%. This increase was primarily due to increases in capital spending during 2002 in connection with system reliability improvements as well as the accelerated amortization of regulatory assets associated with the Seabrook sale of approximately $7.3 million. This increase was offset by the absence of depreciation on NSTAR’s district energy facility, Northwind in 2002. In 2001, Northwind’s assets were written down by $5 million.

DSM and renewable energy program expense was $69 million in 2002 compared to $70.1 million in 2001, a decrease of $1.1 million, or 2%, primarily due to a reduction of DSM programs which is consistent with the collection of conservation and renewable energy revenues. These costs are in accordance with program guidelines established by the MDTE and are collected from customers on a fully reconciling basis. In addition, NSTAR earns revenue incentive amounts in return for increased customer participation. In 2002 and 2001, these incentives amounted to approximately $3 million.

Property and other taxes were $97.2 million in 2002 compared to $96.5 million in 2001, an increase of $0.7 million, or 1%. This increase was due to higher tax rates and assessments, particularly for the City of Boston of $2.2 million offset by lower payments in lieu of taxes to the Town of Plymouth under NSTAR’s agreement with the town.

Income taxes from operations were $107.1 million in 2002 compared to $113.4 million in 2001, a decrease of $6.3 million, or 6%. The decrease in income tax expense is primarily the result of tax benefits relating to certain customer refunds, which reduced income tax expense by approximately $4 million. In addition, this decrease also reflects the tax benefit of deducting NSTAR’s common dividends paid to the NSTAR Saving Plan. These items resulted in a decrease in the effective tax rate for 2002 to 37.3% from 40.2% for 2001.

Other income, net

Other income was $22.4 million in 2002 compared to $6.9 million in 2001, an increase in income of $15.5 million. The increase was due primarily to $7.3 million in accelerated amortization of ITC resulting from the sale of Seabrook, deferred tax valuation allowance adjustments of $3.9 million, a $3.2 million net increase in interest income primarily related to a reversal of a previously established interest reserve and the absence in 2002 of $1.1 million related to system development costs. Other income in 2002 also reflects $1.2 million related to transaction fees.

Other deductions, net

Other deductions were $2 million in both 2002 and in 2001. Deductions in 2002 reflect the absence of a $5 million accrual for shutdown costs recorded in 2001 for the Northwind district energy facility as compared to $2 million in 2002 for an additional charge for expected equipment removal costs and a $0.6 million decline in expense for the minority interest related to this facility. Other deductions also include increased charitable contributions of $0.9 million, offset by $1.5 million in lower miscellaneous deductions, including applicable income tax benefits for total other deductions.

Interest changes

Interest on long-term debt and transition property securitization certificates was $152.6 million in 2002 compared to $158.4 million in 2001, a decrease of $5.8 million, or 4%. The decrease in interest expense reflects the retirement of $24.3 million of Boston Edison’s 9.375% Debentures in August 2001, Boston Edison’s early redemption of 8.25% Debentures of $60 million in September 2002, NSTAR Gas’ 8.99% Series I Bonds of $3.5 million in December 2001, Cambridge Electric’s 7.75% Series D Notes of $2.1 million in June 2002 and ComElectric’s 9.3% $30 million Term

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Loan in January 2002, additional sinking fund payments and the reduction in transition property securitization certificates outstanding of $68.4 million that resulted in reduced interest expense of $4.3 million. Securitization interest represents interest on debt collateralized by the future income stream associated with the stranded costs of the Pilgrim Unit divestiture. These certificates are non-recourse to Boston Edison. Partially offsetting these decreases in interest expense was the impact of the October 15, 2002 Boston Edison issuance of $400 million of 4.875% 10-year debentures and $100 million of 3-year floating rate debentures (2.275% in 2002) priced at three month LIBOR plus 50 basis points. The net proceeds were used to repay consolidated outstanding short-term debt. These new debentures increased interest expense by $5 million in 2002.

Short-term and other interest expense was $26.9 million in 2002 compared to $25.3 million in 2001, an increase of $1.6 million, or 6%. This increase was due to a $14.4 million increase in the carrying charges associated with reductions in the level of under-collection of regulatory deferrals, particularly carrying charges related to deferred transition costs. Short-term and other interest costs reflected a significant reduction in borrowing rates and a $62.2 million lower average level of debt outstanding in 2002, that resulted in an interest savings of approximately $19 million. Short-term borrowing rates averaged approximately 1.9% in 2002 as compared to approximately 4.1% in 2001. Partially offsetting this decrease in short-term expense was a $5.9 million increase in interest costs associated, for the most part, with now resolved tax matters.

The decrease in AFUDC is primarily due to a reduction in the AFUDC rate reflecting the overall decline in short-term debt rates. The 2002 rate was 2.26% compared to 4.31% in 2001. Also contributing to this decrease was the absence in the current period of capitalized interest on the construction of NSTAR’s corporate office facility of approximately $3.3 million. These reductions were partially offset by higher capital project balances during 2002 primarily as a result of electric system infrastructure upgrades.

Liquidity and Capital Resources

During 2003, 2002 and 2001, internal generation of cash provided 136%, 80% and 100%, respectively, of plant expenditures. Internally generated funds consist of cash flows from operating activities, adjusted to exclude changes in working capital and the payment of dividends. NSTAR companies supplement internally generated funds as needed, primarily through the issuance of short-term commercial paper and bank borrowings.

The capital spending level currently forecasted for 2004 is $309 million, consisting of approximately $306 million for electric and gas operations and $3 million for capital requirements of non-utility ventures. The capital spending level over the following four years is currently forecasted to aggregate approximately $1,149 million.

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

NSTAR’s primary estimated uses of cash for 2004 include capital expenditures, dividend payments and debt reductions.

NSTAR has long-term debt principal payments, minimum lease commitments, electric capacity charge obligations under contracts and natural gas contractual agreements at December 31, 2003 for each of the years presented below:

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(in millions)		2004		2005		2006		2007		2008		Years Thereafter
Long-term debt	$	190	$	109	$	179	$	15	$	17	$	1,285
Transition property securitization		69		68		69		69		68		103
Leases		21		17		13		10		9		39
Electric capacity obligations		137		144		143		147		147		700
Gas contractual obligations		50		50		47		37		36		126

	$	467	$	388	$	451	$	278	$	277	$	2,253

Operating activities in 2003 provided $421.5 million of cash. The Company used $289.4 million in its investing activities, primarily to fund $307.6 million of plant expenditures, which included system reliability infrastructure improvement projects incurred by NSTAR Electric and NSTAR Gas operations and expenditures in connection with the Advanced Energy Systems, Inc. generation expansion project.

Operating Activities.

The net cash provided by 2003 operating activities of $421.5 million was partially attributable to net income of $181.6 million, which, when adjusted for depreciation and amortization, deferred income taxes and investment tax credits, provided $548.2 million of cash as compared to $390.2 million in 2002 from net income as similarly adjusted. Deferred income taxes and investment tax credits increased by $141.7 million reflecting the deferred tax impact of a change in the tax laws that allows for an additional 50% acceleration of tax depreciation on additions and amortization of investment tax credits. Despite the increase in 2003 earnings, the decline in operating cash flows in 2003 compared to 2002 was due primarily to the $65 million received in 2002 as part of the completion of a development project and approximately $30 million in increased contributions to NSTAR’s qualified pension plan in 2003. NSTAR currently anticipates that it will contribute approximately $43 million to its Pension Plan and approximately $20 million to its other postretirement benefit plans in 2004. In addition to these factors, the timing of the recovery of energy costs reduced operating cash flows by $164.8 million in 2003 in comparison to 2002. These energy costs will be recovered with a carrying charge from customers in future periods. There is no impact on earnings from the timing of the recovery of energy costs. Changes in other working capital items were primarily caused by the decrease in accounts receivable due to energy billings and the timing of tax payments.

Net Working Capital.

Net working capital components, reflected on the Consolidated Statement of Cash Flows and exclude short-term borrowings and the current portion of long-term debt, decreased by $145 million to a negative working capital position of $23.3 million for 2003 as compared to $121.7 million for 2002. This decrease is primarily due to the decrease in accounts receivable resulting from the buildup of energy billings during 2001 due to higher rates in effect at that time and collection of these billings in 2002 and an increase in accounts payable of $27.1 million due to the timing of energy supply invoices.

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Investing Activities.

The net cash used in investing activities in 2003 of $289.4 million consists primarily of capital expenditures related to transmission and distribution systems and the expansion of NSTAR’s Advanced Energy Systems, Inc. generating facility offset by $17.5 million in net proceeds received from the sale of Blackstone Station.

Financing Activities.

The net cash used in financing activities of $169 million reflects long-term debt redemptions and sinking funds payments of $242.4 million, dividends paid of $116.5 million, a higher level of short-term borrowings of $40.5 million and the proceeds from the issuance of a $150 million three-year Term Loan.

NSTAR has commenced the regulatory filing process to obtain approval to construct a 345 kv transmission line from the southern suburbs of Boston to South Boston in order to assure continued reliability of service and improve power input capacity in the Northeast Massachusetts area (NEMA). If approved, construction is estimated to begin in the fourth quarter of 2004 and 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. This proposed plan is subject to siting and license requirements.

Short-Term Financing Activities.

NSTAR’s short-term debt increased by $40.5 million to $239.1 million at December 31, 2003 as compared to $198.6 million at December 31, 2002. The increase resulted primarily from the refinancing by Boston Edison in October 2002 of short-term debt with the proceeds of long-term debt. In May 2003, ComElectric used the proceeds of its $150 million financing to reduce short-term debt levels. In 2002, NSTAR’s short-term debt decreased $426.2 million primarily as a result of the use of proceeds from Boston Edison’s $500 million financing completed in October 2002 to refinance short-term debt.

On January 14, 2004, Boston Edison gave notice to the Trustee for its debentures that the entire $181 million aggregate principal amount of its 7.80% Debentures due March 15, 2023 will be called for redemption on March 16, 2004 at a price of 103.36% of the principal amount thereof plus accrued interest. As a result, this Debenture is included under current liabilities in the accompanying Consolidated Balance Sheets at December 31, 2003.

In May 2003, ComElectric entered into a $150 million, three-year variable rate unsecured Term Loan with a group of banks. The net proceeds were used to repay outstanding short-term debt balances.

Additionally, in 2003, debt financing activities included the retirement of: $68.7 million in securitization certificates, $150 million for the redemption of Boston Edison’s 6.80% Debentures in March, ComElectric’s 7.43% $15 million Term Loan also in March and other scheduled sinking fund payments. In 2002, debt financing activities included the retirement of: $68.4 million in securitization certificates, ComElectric’s 9.3% $30 million Term Loan in January, Cambridge Electric’s 7.75% $2.1 million Series D Notes in June and $60 million for the early redemption of Boston Edison’s 8.25% Debentures in September.

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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, 2003 and 2002. NSTAR’s long-term debt other than the Mortgage Bonds of NSTAR Gas is unsecured.

The Transition Property Securitization Certificates held by Boston Edison’s subsidiary, BEC Funding, LLC, are collaterized with a securitized regulatory asset with a balance of $425.4 million as of December 31, 2003. Boston Edison, as servicing agent for BEC Funding, collected $102.3 million in 2003. These collected funds are remitted daily to the trustee of BEC Funding. These Certificates are non-recourse to Boston Edison.

NSTAR has a credit facility of $175 million that consists of a three year, $175 million revolving credit agreement that expires on November 14, 2005. At December 31, 2003 and 2002, there were no amounts outstanding under these revolving credit agreements. The $175 million credit facility serves as a backup to NSTAR’s $175 million commercial paper program that, at December 31, 2003 and 2002, had $1.5 million and $63.5 million outstanding, respectively. In October 2002, following receipt of the proceeds of Boston Edison’s $500 million debt issue, the proceeds were used to pay down short-term debt balances. Under the terms of this credit agreement, NSTAR is required to maintain a maximum total consolidated debt to total capitalization ratio of not greater than 65% at all times, excluding Transition Property Securitization Certificates, and excluding Accumulated other comprehensive income (loss) from Common equity, and to maintain a ratio of consolidated earnings before interest and taxes to consolidated total interest expense of not less than 2 to 1 for each period of four consecutive fiscal quarters. Commitment fees must be paid on the total agreement amount. At December 31, 2003 and 2002, 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 went effective on January 9, 2004, but the issuance of debt securities pursuant to the shelf registration is still subject to approval by the MDTE. As of December 31, 2003, no amounts were issued under this shelf registration.

Boston Edison has approval from the FERC to issue short-term debt securities from time to time on or before December 31, 2004, with maturity dates no later than December 31, 2005, in amounts such that the aggregate principal does not exceed $350 million at any one time. Boston Edison has a $350 million revolving credit agreement that expires on November 10, 2004. At December 31, 2003, there was no amount outstanding under this revolving credit agreement. These agreements serve as backup to Boston Edison’s $350 million commercial paper program that had a $182.5 million balance at December 31, 2003 and no outstanding balance at December 31, 2002. In October 2002, following receipt of the proceeds of its $500 million debt issue, its short-term debt balance was reduced to zero. Under the terms of this agreement, Boston Edison is required to maintain a maximum total debt to capitalization ratio of not greater than 60% at all times, excluding Transition Property Securitization Certificates, and excluding Accumulated other comprehensive income (loss) from Common equity, and to maintain a ratio of consolidated earnings before interest and taxes to consolidated total interest expense of not less than 2 to 1 for each period of four consecutive fiscal quarters. At December 31, 2003 and 2002, Boston Edison was in full compliance with all of its covenants in connection with its short-term credit facilities.

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Electric have FERC authorization to issue short-term securities from time-to-time on or before November 30, 2004 and June 27, 2004, with maturity dates no later than November 29, 2005 and June 26, 2005, respectively, in amounts such that the aggregate principal does not exceed $125 million and $60 million, respectively, at any one time. NSTAR Gas is not required to seek approval from FERC to issue short-term debt.

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. 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” further discussed below.

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 October 1, 2003, NSTAR Electric initiated the process to auction off certain power purchase agreements under which the Company had contracted to purchase approximately 1,100 megawatts of power under long-term contracts with non-utility generators. The auction is intended to further NSTAR’s efforts to mitigate stranded costs, which continue to be recovered from customers. Any sale or restructuring of the power purchase agreements would serve to fix and/or reduce costs that are currently collected from customers. Currently, NSTAR Electric cannot predict the timing and outcome of this auction nor the ultimate impact on its financial position or cash flows. NSTAR Electric does not expect an impact to earnings since the proceeds would be used to lower costs that are passed through to customers in rates.

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 December 31, 2004. 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, 2004 through June 30, 2004 and

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for 50% of its obligation, other than large customers, for the second half of 2004. 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 2004. 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. All of NSTAR Electric’s power suppliers 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 with 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. NSTAR Electric’s policy is to enter into power supply arrangements only if the supplier (or its parent guarantor) has an investment grade or better credit rating. In view of current volatility in the energy supply industry, NSTAR Electric is unable to determine whether its suppliers (or their parent guarantors) will become subject to financial difficulties, or whether these financial assurances and guarantees are sufficient. In the event the supplier (or its guarantor) 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 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 credit rating below investment grade, that company could be required to provide additional security for performance, such as a letter of credit.

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

The cost of gas procured for firm gas sales customers is recovered through a semi-annual cost of gas adjustment mechanism. Under MDTE regulations, interim adjustments to the cost of gas may also be requested if market volatility causes swings in the price of gas.

NSTAR Gas continually evaluates the financial stability of current and prospective gas suppliers. Firm suppliers are required to have and maintain investment grade credit ratings and the firm gas supply agreements allow either party to require financial assurance, or, if necessary, contract termination in the event that either party is downgraded below investment 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, 2003, outstanding guarantees totaled $32.1 million as follows:

(in thousands)
Letters of Credit	$	5,527
Surety Bonds		15,476
Other Guarantees		11,100

Total Guarantees	$	32,103

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The $5.5 million letter of credit is for the benefit of a third party, as trustees 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, 2003, there have been no amounts drawn under this letter of credit.

As of December 31, 2003, certain of NSTAR’s subsidiaries have purchased a total of $0.7 million of performance surety bonds for the purpose of obtaining licenses, permits and rights-of-way in various municipalities. In addition, NSTAR has purchased approximately $14.7 million in workers’ compensation self-insurer bonds. These bonds support the guarantee by NSTAR to the Commonwealth of Massachusetts required as part of NSTAR’s workers’ compensation self-insurance program.

NSTAR and its subsidiaries have also issued $11 million of residual value guarantees related to its equity interest in the Hydro-Quebec transmission companies.

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

Preferred Stock Dividends and Redemptions

Preferred dividends of Boston Edison were approximately $2 million, $2 million and $5.6 million in 2003, 2002 and 2001, respectively. On December 3, 2001, Boston Edison redeemed all 500,000 shares outstanding of its Cumulative Preferred Stock, 8% Series, at the mandatory redemption price of $100 per share, plus accrued dividends.

Contingencies

Environmental Matters

As of December 31, 2003, NSTAR’s subsidiaries are involved in 5 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 $0.7 million and $0.8 million are included as liabilities in the accompanying Consolidated Balance Sheets at December 31, 2003 and 2002, respectively.

In addition to the MCP sites, NSTAR subsidiaries also face possible liability as a result of involvement in 12 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, 2003 and 2002.

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

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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, 2003 and 2002, NSTAR has recorded a liability of approximately $4.4 million and $4.8 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 or results of operations for a reporting period.

Employees and Employee Relations

As of December 31, 2003, NSTAR had approximately 3,200 employees, including approximately 2,400, or 75%, who are represented by three units covered by separate collective bargaining contracts.

Local 369 of the Utility Workers Union of America, AFL-CIO, represents approximately 2,000 employees with a contract that expires on May 15, 2005. Approximately 260 employees represented by Local 12004, United Steelworkers of America, AFL-CIO-CLC, have a contract that expires on March 31, 2006. Approximately 70 employees of Advanced Energy Systems’ MATEP subsidiary are represented by Local 877, International Union of Operating Engineers, AFL-CIO, with a contract that expires on September 30, 2006.

Management believes it has satisfactory relations with its employees.

Interest Rate Risk

NSTAR is exposed to changes in interest rates primarily based on levels of short-term debt outstanding. The weighted average interest rates for long-term indebtedness, including current maturities were 6.45% and 6.81% in 2003 and 2002, respectively. Carrying amounts and fair values of long-term indebtedness (excluding notes payable, including current maturities) as of December 31, 2003 and 2002, were as follows:

	2003		2002

	Carrying	Fair		Carrying	Fair
(in thousands)	Amount	Value		Amount	Value
Long-term indebtedness	$2,212,564	$2,485,190		$2,304,101	$2,422,440
(including current maturities)

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

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Although NSTAR has material commodity purchase contracts, these instruments are not subject to market risk. NSTAR’s electric and gas distribution subsidiaries have rate-making mechanisms that allow for the recovery of fuel costs from customers. Customers have the option of continuing to buy power from the retail electric distribution businesses at standard offer prices through February 2005. The cost of providing standard offer service includes fuel and purchased power costs. Default service is the electricity that is supplied by the local distribution company when a customer is not receiving power from standard offer service. The market prices for standard offer and default service 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.

In addition, NSTAR’s exposure to financial market risk results primarily from fluctuations in interest rates. On May 14, 2003, Commonwealth Electric Company 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 Financial Information

NSTAR

Consolidated Statements of Income

		Years ended December 31,

		2003			2002			2001
		(in thousands, except earnings per share)

Operating revenues	$	2,914,131		$	2,691,573		$	3,184,046


Operating expenses:
Purchased power and cost of gas sold		1,613,177			1,409,700			1,905,201
Operations and maintenance		443,931			431,740			417,141
Depreciation and amortization		235,516			239,233			230,949
Demand side management and
renewable energy programs		66,217			68,986			70,093
Property and other taxes		97,837			97,204			96,489
Income taxes		121,409			107,113			113,412


Total operating expenses		2,578,087			2,353,976			2,833,285


Operating income		336,044			337,597			350,761


Other income (deductions):
Write-down of RCN investment, net		(4,450	)		(17,677	)		(173,944	)
Other income, net		14,397			22,364			6,923
Other deductions, net		(1,712	)		(1,994	)		(1,951	)


Total other income (deductions), net		8,235			2,693			(168,972	)


Interest charges:
Long-term debt		121,027			115,473			116,939
Transition property securitization		32,715			37,135			41,475
Short-term debt and other		11,576			26,890			25,268
Allowance for borrowed funds used during
construction (AFUDC)/capitalized interest		(4,573	)		(2,875	)		(5,094	)


Total interest charges		160,745			176,623			178,588


Preferred stock dividends of subsidiary		1,960			1,960			5,627

Net income (loss)	$	181,574		$	161,707		$	(2,426	)




Weighted average common shares outstanding:
Basic		53,033			53,033			53,033
Diluted		53,399			53,297			53,216
Earnings (loss) per common share:
Basic	$	3.42		$	3.05		$	(0.05	)
Diluted	$	3.40		$	3.03		$	(0.05	)

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

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NSTAR
Consolidated Statements of Comprehensive Income

		Years ended December 31,

		2003			2002			2001
		(in thousands)

Net income (loss)	$	181,574		$	161,707		$	(2,426	)
Other comprehensive income, net:
Unrealized gain (loss) on investments		2,783			(17,819	)		(7,789	)
Reclassification adjustment for (gain) loss
included in net income		(2,783	)		15,110			66,836
Additional minimum pension liability		1,104			(12,470	)		1,004
Deferred income taxes		(389	)		5,927			(24,146	)

Comprehensive income	$	182,289		$	152,455		$	33,479

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

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NSTAR
Consolidated Statements of Retained Earnings

		Years ended December 31,

		2003		2002		2001
		(in thousands)

Balance at the beginning of the year	$	382,886	$	334,138	$	446,587
Add:
Net income (loss)		181,574		161,707		(2,426	)

Subtotal		564,460		495,845		444,161

Deduct:
Dividends declared:
Common shares		115,346		112,959		110,042

Provision for preferred stock redemption		-		-		(19	)

Balance at the end of the year	$	449,114	$	382,886	$	334,138

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

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NSTAR
Consolidated Balance Sheets

		December 31,

		(in thousands)
		2003					2002

Assets
Utility plant in service, at original cost	$	4,254,848				$	4,090,843
Less: accumulated depreciation		1,109,248		$	3,145,600		1,075,094		$	3,015,749

Construction work in progress					70,500					66,047

Net utility plant					3,216,100					3,081,796
Non-utility property, net					160,556					129,918
Goodwill					439,122					451,374
Equity investments					15,322					19,845
Other investments					53,566					50,444
Current assets:
Cash and cash equivalents		16,526					53,438
Restricted cash		13,144					33,899
Accounts receivable, net of allowance of
$23,424 and $24,379, respectively		306,815					298,428
Accrued unbilled revenues		45,559					47,420
Inventory, at average cost		79,743					58,555
Other		39,172			500,959		14,886			506,626

Deferred debits:
Regulatory assets - power contracts					799,087					773,922
Regulatory assets - retiree benefit costs					340,111					445,041
Regulatory assets - other					715,849					782,914
Other					79,988					96,574

Total assets				$	6,320,660				$	6,338,454




Capitalization and Liabilities
Common equity:
Common shares, par value $1 per share,
100,000,000 shares authorized; 53,032,546
shares issued and outstanding	$	53,033				$	53,033
Premium on common shares		866,221					870,877
Retained earnings		449,114					382,886
Accumulated other comprehensive loss		(6,776	)	$	1,361,592		(7,491	)	$	1,299,305

Cumulative non-mandatory redeemable preferred
stock of subsidiary					43,000					43,000
Long-term debt					1,605,381					1,645,465
Transition property securitization					377,150					445,890
Current liabilities:
Long-term debt		189,956					172,191
Transition property securitization		40,077					40,555
Notes payable		239,100					198,600
Property taxes and other		8,798					9,826
Deferred income taxes		13,961					4,692
Accounts payable		224,987					230,939
Accrued interest		34,490					38,811
Dividends payable		29,760					28,964
Accrued expenses		89,544					94,418
Other		69,246			939,919		67,141			886,137

Deferred credits:
Accumulated deferred income taxes and
unamortized investment tax credits					765,507					675,881
Power contracts					799,087					773,922
Pension liability					46,659					206,236
Regulatory liability - cost of removal					223,074					234,176
Other					159,291					128,442

Commitments and contingencies


Total capitalization and liabilities				$	6,320,660				$	6,338,454

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,

		2003			2002			2001
		(in thousands)
Operating activities:
Net income (loss)	$	181,574		$	161,707		$	(2,426	)
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depreciation and amortization		236,336			239,800			230,949
Deferred income taxes and investment tax credits		128,379			(13,311	)		(29,250	)
Loss on write-down of RCN investment		6,146			37,343			168,376
Demutualization income		-			-			(4,537	)
Allowance for borrowed funds used during construction/capitalized interest		(4,573	)		(2,875	)		(5,094	)
Power contract buyout		(12,741	)		(12,741	)		(12,741	)
Net changes in:
Accounts receivable and accrued unbilled revenues		(6,526	)		166,425			19,483
Fuel, materials and supplies, at average cost		(21,188	)		9,554			(8,617	)
Other current assets		(3,531	)		17,422			1,367
Accounts payable		6,789			33,859			(53,216	)
Other current liabilities		1,151			(105,582	)		(120,407	)
Deferred debits and credits		(86,314	)		68,165			92,907
Net change from other miscellaneous operating activities		(3,970	)		(13,439	)		48,393

Net cash provided by operating activities		421,532			586,327			325,187


Investing activities:
Plant expenditures (excluding AFUDC/capitalized interest)		(307,655	)		(368,084	)		(229,867	)
Proceeds on sale of property		17,572			26,866			-
Other investments		669			9,445			3,231

Net cash used in investing activities		(289,414	)		(331,773	)		(226,636	)


Financing activities:
Redemptions:
Preferred stock		-			-			(50,000	)
Long-term debt		(242,357	)		(166,917	)		(99,728	)
Debt issue costs		(663	)		(5,218	)		-
Issuance of long-term debt		150,000			500,000			-
Net change in notes payable		40,500			(426,247	)		156,500
Dividends paid		(116,510	)		(114,389	)		(115,541	)

Net cash used in financing activities		(169,030	)		(212,771	)		(108,769	)

Net (decrease) increase in cash and cash equivalents		(36,912	)		41,783			(10,218	)
Cash and cash equivalents at the beginning of the year		53,438			11,655			21,873

Cash and cash equivalents at the end of the year	$	16,526		$	53,438		$	11,655




Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest, net of amounts capitalized	$	154,956		$	155,265		$	177,239
Income taxes (refund)	$	(4,526	)	$	95,980		$	198,326
Supplemental disclosure of investing activity:
Investment in common shares	$	-		$	-		$	4,537

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

2. Basis of Consolidation and Accounting

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

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

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

4. Utility Plant

Utility plant is stated at original cost. 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)		2003			2002
Land	$	15,604		$	15,700
Energy production equipment		132,487			71,333
Telecommunications equipment		38,314			37,856
Gas storage		42,701			42,701
Buildings and improvements		2,992			2,992

		232,098			170,582
Less: accumulated depreciation		(72,123	)		(68,238	)

		159,975			102,344
Construction work in progress		581			27,574

	$	160,556		$	129,918

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 3.04%, 3.26% and 3.02% in 2003, 2002 and 2001, 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:

		Depreciable
Plant Component		Life
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 $3.9 million and $8.5 million for 2003 and 2002, respectively.

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

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

8. Allowance for Borrowed Funds Used During Construction (AFUDC)/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 2003, 2002 and 2001 were 1.60%, 2.26% and 4.31%, respectively, and represented only the costs of short-term debt that excludes the impact of capitalized interest.

NSTAR capitalizes interest costs on long-term construction projects related to its unregulated businesses. Interest costs aggregating $3.7 million during 2003 were capitalized for the construction of new combustion turbines at AES’ MATEP facility.

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.

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 settlement agreement, this premium will continue to be amortized over 40 years and amounts to approximately $12.2 million annually, while the costs to achieve (CTA) are being amortized over 10 years. CTA are the costs incurred to execute the

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merger including the employee costs for 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 based on the original rate plan, as approved by the MDTE through the rate freeze period. 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 2003 was approximately $12.9 million, an increase of $1.8 million from 2002. NSTAR will reconcile the actual CTA costs incurred with the original estimate in a future rate proceeding. This reconciliation will include a final accounting of the deductibility for income tax purposes of each component of CTA. The total CTA is approximately $143 million. This increase from the original estimate is partially mitigated by the fact that the portion of CTA that is not deductible for income tax purposes is approximately $20 million lower than the original estimate. NSTAR anticipates that these incremental costs are probable of recovery in future rates. The CTA and Goodwill amounts were filed and approved as part of the rate plan.

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. 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 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 per share amounts)		Years ended December 31,

		2003			2002			2001
Net income (loss)	$	181,574		$	161,707		$	(2,426	)
Add: Share grant incentive compensation
expense included in reported net income,
net of related tax effects		2,147			1,642			1,241
Deduct: Total share grant and stock option
compensation expense determined under
fair value method for all awards, net
of related tax effects		(2,870	)		(2,489	)		(1,972	)

Pro forma net income (loss)	$	180,851		$	160,860		$	(3,157	)

Earnings (loss) per share:
Basic - as reported	$	3.42		$	3.05		$	(0.05	)
Basic - pro forma	$	3.41		$	3.03		$	(0.06	)
Diluted - as reported	$	3.40		$	3.03		$	(0.05	)
Diluted - pro forma	$	3.39		$	3.02		$	(0.06	)

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13. Other Income (Deductions), net

Major components of other income were as follows:

		Years ended December 31,

(in thousands)		2003		2002			2001
Equity earnings, dividends and other
investment income	$	2,205	$	2,667		$	2,258
Gain on demutualized securities		-		4,928			4,461
Interest and rental income		3,244		5,025			5,829
Tax valuation allowance adjustment		8,485		3,849			-
Investment tax credit		-		7,272			-
Settlement of claims		-		-			1,818
Miscellaneous other income, (includes
applicable income tax expense)		463		(1,377	)		(7,443	)

	$	14,397	$	22,364		$	6,923

Major components of other deductions were as follows:

		Years ended December 31,

(in thousands)		2003			2002			2001
Shutdown costs of unregulated business	$	-		$	(2,000	)	$	(5,000	)
Charitable contributions		(1,268	)		(1,175	)		(237	)
Miscellaneous other deductions, (includes
applicable income tax benefit)		(470	)		656			2,210
Minority interest		26			525			1,076

	$	(1,712	)	$	(1,994	)	$	(1,951	)

14. New Accounting Standards

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NSTAR has a wholly owned special purpose subsidiary, BEC Funding LLC, established to facilitate the sale and administration of $725 million in notes to a special purpose trust created by two Massachusetts state agencies. Historically, NSTAR has consolidated this entity. As part of NSTAR’s assessment of FIN 46R, 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 variable entity and should continue to be consolidated by NSTAR.

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

During 2001, as part of NSTAR Electric’s normal business operations in order to meet its energy obligation to its standard offer customers, NSTAR Electric entered into hourly transactions to purchase or sell energy supply to its ISO-NE. The NSTAR Electric transactions with the ISO-NE have been treated as the ISO-NE servicing the incremental needs of NSTAR Electric, that is, transactions with ISO-NE associated with the difference between NSTAR Electric’s resource needs compared to NSTAR Electric’s resource availability. NSTAR Electric records the net effect of transactions with the ISO-NE as an adjustment to purchased power expense.

During 2003 and 2002, NSTAR Electric entered into an agreement whereby all of its energy supply resource entitlements are transferred to an independent energy supplier, following which NSTAR Electric repurchases its energy resource needs from this independent energy supplier for NSTAR Electric’s ultimate sale to its standard offer customers. This transaction has been and will continue to be recorded as a net purchase, similar to those transactions with ISO-NE during 2001.

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Note B. Earnings Per Common Share

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

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

(in thousands, except per share amounts)		2003		2002		2001
Net income (loss)	$	181,574	$	161,707	$	(2,426	)
Basic EPS	$	3.42	$	3.05	$	(0.05	)
Diluted EPS	$	3.40	$	3.03	$	(0.05	)
Weighted average common shares outstanding for
basic EPS		53,033		53,033		53,033
Effect of dilutive shares:
Weighted average dilutive potential common shares		366		264		183

Weighted average common shares outstanding for diluted EPS		53,399		53,297		53,216

Note C. Investments - Available for Sale Securities

NSTAR classifies its investments in marketable securities as available for sale. As of December 31, 2003, NSTAR did not own any investments in marketable securities. However, as of December 31, 2002, NSTAR owned approximately 11.6 million common shares of RCN Corporation (RCN).

On December 24, 2003, NSTAR exited from its investment in RCN and formally abandoned the 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. As a result of this abandonment, the investment was written down to $0 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.

As of December 31, 2002, the total carrying value of the 11.6 million RCN common shares, included in Other investments on the accompanying Consolidated Balance Sheets, was recorded at its estimated fair value of approximately $6.1 million, or $0.53 per share. The fair value of the 11.6 million shares held increased during 2003 as a result of changes in the market value of RCN common shares.

In accordance with its accounting policies, NSTAR continuously evaluated the carrying value of its investment in RCN to assess whether any decline in the market value below its carrying value was deemed to be other than temporary. Consistent with the performance of the telecommunications sector as a whole, the market value of RCN common shares decreased significantly during the later part of 2000 and continued to decrease through 2002. As a result management determined that this decline in market value was “other-than-temporary and

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recorded impairment charges” in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.”

Note D. Asset Retirement Obligations

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.

NSTAR has identified several long-lived assets, in which it has legal obligations to remove such property, for its non-regulated businesses. Based on current information and assumptions, NSTAR, in the first quarter of 2003, 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 is recorded as part of Depreciation and amortization expense on the accompanying Consolidated Statements of Income.

Note E. 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.

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Regulatory assets consisted of the following:

	December 31,

(in thousands)		2003		2002
Power contracts (including Yankee units)	$	799,087	$	773,922
Retiree benefit costs		340,111		445,041
Regulatory assets - other:
Generation-related regulatory assets, net		504,594		538,287
Merger costs to achieve		93,112		105,992
Income taxes, net		50,161		50,666
Purchased power costs		31,969		30,375
Redemption premiums		12,340		13,479
Other		23,673		44,115

Total regulatory assets	$	1,855,047	$	2,001,877

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 close the Connecticut Yankee (CY), Yankee Atomic (YA) and Maine Yankee (MY) nuclear power plants that are currently being decommissioned was $133.3 million at December 31, 2003. NSTAR’s liability for CY decommissioning and its recovery end in 2007, for YA in 2010 and for MY in 2008. However, should the actual costs exceed current estimates and anticipated decommissioning dates, NSTAR could have an obligation beyond these periods that would be fully recoverable. These costs are recovered through NSTAR Electric’s transition charge. Refer to Note Q, “Commitments and Contingencies,” for more discussion.

The remaining balance at December 31, 2003 of $665.8 million represents the recognition of six purchased power contracts as derivatives and their above-market value and future recovery through NSTAR Electric’s transition charges. Refer to Note F, “Derivative Instruments - Power Contracts” 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 2016 for Boston Edison, through 2023 for ComElectric and through 2011 for Cambridge Electric. This schedule is subject to adjustment by the MDTE.

As of December 31, 2003, $425.4 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.

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Retiree benefit costs

The retiree benefit regulatory asset of $340.1 million is comprised of the additional minimum pension liability charge required under SFAS 87 ($299.3 million), $16.3 million of carrying charges related to the MDTE order, which will be recovered from customers in 2004, and $13.1 million of pension and PBOP costs deferred under the MDTE order, which will be amortized over three years beginning in 2004. The remaining balance of $11.5 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.

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. These costs have been adjusted since the original recovery began and any unrecovered costs will be included in each company’s next rate case filing.

Income taxes, net

The principal holder of this regulatory asset is Boston Edison. Approximately $31 million of this regulatory asset balance reflects deferred tax reserve deficiencies that the MDTE has allowed recovery of from ratepayers over a 17-year period. In addition, approximately $39 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 $20 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 have 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 reserves and response costs that represent the recovery of costs to clean up former gas manufacturing sites over a 7-year period without a return.

Note F. 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). The accounting for derivative financial instruments is subject to change based on the guidance received from the DIG of FASB. The DIG issued No. C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity” on October 10, 2001, which specifically addressed the interpretation of clearly and closely related contracts that qualify for the normal purchases and sales exception under SFAS 133. The conclusion reached by the DIG was that contracts with a pricing mechanism that is subject to future adjustment based on a generic index that is not specifically related to the contracted service commodity generally would not qualify for the normal purchases and sales exception.

NSTAR has six purchased power contracts that contain components with pricing mechanisms that are based on a pricing index, such as the Gross National Product or Consumer Price Index. Although these factors are only applied to certain ancillary pricing components of these agreements, as required by the interpretation of DIG Issue C15, NSTAR began recording these contracts at fair value on its Consolidated Balance Sheets during 2002. As a result, the recognition of a liability for the fair value of the above-market portion of these contracts at December 31, 2003 is approximately $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 transition charge. Therefore, as a result of this regulatory treatment, the recording of these contracts on its accompanying Consolidated Balance Sheets does not result in an earnings impact.

NSTAR has other purchased power contracts in which the contract value is significantly above-market. However, these contracts have met the criteria for the normal purchases and sales exception pursuant to SFAS 133 and DIG Issue C15 and have not been recorded on the accompanying Consolidated Balance Sheets. The above-market portion of these contracts is currently being recovered through the transition charge. Therefore, NSTAR does not account for these types of capacity and energy contracts, gas supply contracts, or purchase orders for numerous supply arrangements as derivatives.

Note 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 $50.2 million and $50.7 million and corresponding net increases in accumulated deferred income taxes were recorded as of December 31, 2003 and 2002, respectively. The regulatory assets represent the additional future revenues to be collected from customers for deferred income taxes.

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

		December 31,

(in thousands)		2003		2002
Deferred tax liabilities:
Plant-related	$	495,617	$	421,599
Transition costs		178,840		206,895
Other		239,531		206,569

		913,988		835,063


Deferred tax assets:
Plant-related		55,503		59,155
Investment tax credits		17,190		18,317
Other		88,736		105,649

		161,429		183,121

Net accumulated deferred income taxes		752,559		651,942
Accumulated unamortized investment tax credits		26,909		28,631

	$	779,468	$	680,573

The tax valuation allowance at December 31, 2003 and 2002 was zero and $53 million, respectively, and is included in Deferred tax assets - other in the table above.

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

Components of income tax expense were as follows:

(in thousands)		2003			2002			2001
Current income tax expense	$	39,188		$	89,201		$	148,230
Deferred income tax expense (benefit)		83,944			19,886			(32,735	)
Investment tax credit amortization		(1,723	)		(1,974	)		(2,083	)

Income taxes charged to operations		121,409			107,113			113,412

Tax (benefit) expense on other income net:
Current income tax expense (benefit)		(54,668	)		5,352			6,465
Deferred income tax expense (benefit)		46,157			(30,789	)		5,567

		(8,511	)		(25,437	)		12,032

Total income tax expense	$	112,898		$	81,676		$	125,444

Tax expense on other income, net reflects $7.3 million in 2002 of investment tax credits recognized as a result of the sale of Seabrook.

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

	2003		2002		2001
Statutory tax rate	35.0	%	35.0	%	35.0	%
State income tax, net of federal income tax benefit	5.3		4.8		5.3
Investment tax credits	(0.6	)	(3.2	)	(0.7	)
Other	1.4		1.0		5.1

Effective tax rate before write-down and tax valuation allowance adjustment	41.1		37.6		44.7
Adjustment to tax valuation allowance and write- down of RCN investment (federal and state)	(2.8	)	(4.0	)	57.3

Effective tax rate	38.3	%	33.6	%	102.0	%

a. Tax Valuation Allowance

SFAS 109 prohibits the recognition of all or a portion of deferred income tax benefits if it is more likely than not that the deferred tax asset will not be realized. NSTAR had determined that it was more likely than not that a current or future income tax benefit would not be realized relating to the write-downs of its RCN investment that were recorded in the second and fourth quarters of 2002 and previously in the first quarter of 2001. These write-downs resulted from the significant declines in the market value of the telecommunications sector, including RCN. As a result of this uncertainty, NSTAR recorded a $77.6 million tax valuation allowance on the entire tax benefit associated with these write-downs. During 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 Internal Revenue Service (IRS) review of NSTAR’s 1999 and 2000 federal income tax returns, NSTAR determined that it was more likely than not that it would ultimately recognize the tax benefits relating to the incremental operating losses from the joint venture that were allocated to NSTAR. These returns are currently being audited by the IRS as part of their normal review of NSTAR’s consolidated federal income tax returns. The tax valuation allowance included reserves 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 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 will claim 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.

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b. Tax Gain on Generating Assets

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.

Note H. Pension and Other Postretirement Benefits

1. Pension

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

In 2002, the Plan was amended to comply with the Economic Growth and Tax Relief Reconciliation Act of 2001 (EGTRRA). EGTRRA, among other things, increased the annual benefits limit for amounts payable from the Plan, increased the number of rollover options for distributions, and allowed surviving spouses to rollover distributions to their employer’s plan. This amendment also brought the Plan into conformance with recently issued IRS revenue rulings and regulations that require the change of the mortality table used for computing lump sum pension distributions and annuity conversions.

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

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

		December 31,

(in thousands)		2003			2002
Change in benefit obligation:
Benefit obligation, beginning of the year	$	949,646		$	824,302
Service cost		17,976			15,280
Interest cost		58,826			59,658
Plan participants’ contributions		72			74
Plan amendments		-			671
Actuarial loss		4,920			108,037
Additional accrued benefits		-			15,194
Settlement payments		(18,846	)		(21,529	)
Benefits paid		(51,565	)		(52,041	)

Benefit obligation, end of the year	$	961,029		$	949,646




Change in Plan assets:
Fair value of Plan assets, beginning of the year	$	665,897		$	790,704
Actual gain (loss) on Plan assets, net		150,978			(105,578	)
Employer contribution		82,590			54,267
Plan participants’ contributions		72			74
Settlement payments		(18,846	)		(21,529	)
Benefits paid		(51,565	)		(52,041	)

Fair value of Plan assets, end of the year	$	829,126		$	665,897

The Plan’s funded status was as follows:

		December 31,

(in thousands)		2003			2002
Funded status	$	(131,903	)	$	(283,749	)
Unrecognized actuarial net loss		403,312			523,967
Unrecognized transition obligation		379			980
Unrecognized prior service cost		(2,962	)		(2,829	)

Net amount recognized	$	268,826		$	238,369

Amounts recognized in the accompanying Consolidated Balance Sheets consisted of:

		December 31,

(in thousands)		2003			2002
Accrued retirement liability	$	(46,659	)	$	(198,280	)
Intangible asset		4,835			6,379
Accumulated other comprehensive income		11,368			4,515
Regulatory asset		299,282			425,755

Net amount recognized	$	268,826		$	238,369

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the supplemental retirement plan with accumulated benefit obligations in excess of plan assets were $34,317,000, $32,176,000 and $0, respectively, as of December 31, 2003 and $32,154,000, $28,561,000 and $0, respectively, as of December 31, 2002.

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Weighted average assumptions were as follows:

	2003	2002	2001
Discount rate at the end of the year	6.25%	6.5%	7.25%
Expected return on Plan assets for the year (net of expenses)	8.4%	9.4%	9.4%
Rate of compensation increase at the end of the year	4.0%	4.0%	4.0%

NSTAR’s discount rate is based on rates of high quality corporate bonds of appropriate maturities as published by nationally recognized rating agencies and through periodic bond portfolio matching. NSTAR’s long-term rate of return is based on past performance and economic forecasts for the types of investments held in the Plan. This rate is presented net of both administrative expenses and investment expenses, which have averaged approximately 0.6% for 2003 and 2002. NSTAR pays both types of expenses for the Plan.

Components of net periodic benefit cost/(income) were as follows:

		Years ended December 31,

(in thousands)		2003			2002			2001
Service cost	$	17,976		$	15,280		$	14,082
Interest cost		58,826			59,658			57,381
Expected return on Plan assets		(58,917	)		(74,426	)		(78,397	)
Amortization of prior service cost		133			80			80
Amortization of transition obligation		601			601			601
Recognized actuarial loss		33,514			13,530			830

Net periodic benefit cost/(income)	$	52,133		$	14,723		$	(5,423	)

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

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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 31^st as well as the Plan’s target percentages and the permissible range:


	Plan Assets		Target	Permissible

	2003	2002	Percentages	Ranges

Asset Category
Equity securities	50%	58%	50%	45% - 55%
Debt securities	31%	31%	25%	20% - 30%
Real Estate	5%	0%	10%	5% - 15%
Other	14%	11%	15%	10% - 20%

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 and 2002 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. Assets are diversified by both asset class (i.e., equities, bonds) and within asset classes (i.e., economic sector, industry).

No more than 6% of an asset manager’s equity portfolio market value may be invested in one company. The total equity portfolio should be invested in at least 20 different companies in different industries. No more than 50% of the total equity portfolio’s market value may be invested in one industry sector.

Domestic and international fixed income investments are permitted and may include government obligations, corporate bonds, preferred stock, and asset-backed securities. No more than 5% of an investment manager’s portfolio may be invested in any one security of an issuer, except the U.S. Government and its agencies.

Funded Status

NSTAR’s qualified Plan assets were affected by significant declines in the financial markets from 2000 through 2002. These conditions have impacted the funded status of the Plan at both December 31, 2003 and 2002. As a result of the negative investment performance and, despite the positive Plan investment performance in 2003, at December 31, 2003 and 2002, the accumulated benefit obligation exceeded Plan assets. Therefore, NSTAR is required to recognize an additional minimum liability as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS 87) and SFAS No. 132, “Employers’ Disclosures about Pensions and Postretirement Benefits.” The additional minimum liability results in the netting of the prepaid pension cost with the additional minimum liability on the accompanying Consolidated Balance Sheet.

Under SFAS 87, NSTAR is also required to net its prepaid pension balance. The additional minimum pension liability adjustment, which is equal to the sum of the minimum pension liability and the prepaid pension adjustment, would be recorded, net of taxes, as a non-cash charge to Other Comprehensive Income (OCI) on the accompanying Consolidated Statements of Comprehensive Income and would not affect the results of operations. The fair value of Plan assets and the ABO are measured at each year-end balance sheet date. The minimum liability will be adjusted each year to reflect this measurement. At such time that the Plan assets exceed the ABO, the minimum liability would be reversed.

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 mentioned above. As of December 31, 2003 and 2002, NSTAR has recorded a regulatory asset of $321 million and $426 million, respectively. The regulatory asset is shown as part of Deferred debits in the accompanying Consolidated Balance Sheets.

NSTAR anticipates contributing approximately $43 million to this Plan in 2004.

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The estimated future benefit payments for the years after 2003 are as follows:

(in thousands)
2004	$	58,190
2005		59,491
2006		61,173
2007		63,694
2008		66,384
2009 - 2013		387,885

Total	$	696,817

2. Other Postretirement Benefits

NSTAR provides health care and other benefits to retired employees who meet certain age and years of service eligibility requirements. These benefits included health and life insurance coverage and until April 1, 2003, 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 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 which are inherent in the Act. The Act entitles these employers to a direct tax-exempt federal subsidy. However, since the effective date of the Act was December 2003 and because most employers have not had time to consider the accounting considerations and that there is no appropriate accounting guidance for the federal subsidy, the FASB issued this FSP to allow employers a one-time election to defer recognition of the impact of the Act in the employer’s accounting until formal guidance is issued. NSTAR elected to defer recognition of the provisions of this Act until further accounting guidance is issued. As a result, the provisions of the Act are not reflected in the following disclosure. The issuance of formal accounting guidance may require a change to previously reported information. NSTAR is continuing to monitor the impact of the Act.

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

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

		December 31,

(in thousands)		2003			2002
Change in benefit obligation:
Benefit obligation, beginning of the year	$	571,673		$	469,903
Service cost		7,076			5,204
Interest cost		35,383			33,170
Plan participants’ contributions		1,517			1,490
Plan amendments		9,919			(20,908	)
Actuarial (loss) gain		(868	)		110,055
Benefits paid		(29,217	)		(27,241	)

Benefit obligation, end of the year	$	595,483		$	571,673




Change in plan assets:
Fair value of plan assets, beginning of the year	$	215,074		$	225,848
Actual gain (loss) on plan assets		53,737			(23,523	)
Employer contribution		38,921			38,500
Plan participants’ contributions		1,517			1,490
Benefits paid		(29,217	)		(27,241	)

Fair value of plan assets, end of the year	$	280,032		$	215,074

The plans’ funded status were as follows:

		December 31,

(in thousands)		2003			2002
Funded status	$	(315,451	)	$	(356,599	)
Unrecognized actuarial net loss		233,157			283,651
Unrecognized transition obligation		16,396			56,168
Unrecognized prior service cost		10,855			(35,730	)

Net amount recognized	$	(55,043	)	$	(52,510	)

Weighted average assumptions were as follows:

	2003		2002		2001
Discount rate at the end of the year	6.25	%	6.5	%	7.25	%
Expected return on plan assets for the year	8.0	%	9.0	%	9.0	%

For measurement purposes a 9% weighted annual rate increase in per capita cost of covered medical claims was assumed for 2004. 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% and 5%, respectively.

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

	One-Percentage-Point
(in thousands)		Increase		Decrease
Effect on total service and interest costs components for 2003	$	4,172	$	(3,375	)
Effect on December 31, 2003 postretirement benefit obligation	$	51,054	$	(44,971	)

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Components of net periodic benefit cost were as follows:

		Years ended December 31,

(in thousands)		2003			2002			2001
Service cost	$	7,076		$	5,204		$	4,332
Interest cost		35,383			33,170			31,662
Expected return on Plan assets		(19,088	)		(22,655	)		(21,430	)
Amortization of prior service cost		1,285			(1,411	)		(1,411	)
Amortization of transition obligation		1,821			5,616			5,616
Recognized actuarial loss		13,303			6,588			2,352

Net periodic benefit cost	$	39,780		$	26,512		$	21,121

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

NSTAR anticipates contributing approximately $20 million to its other postretirement benefit plan in 2004.

The estimated future benefit payments for the years after 2003 are as follows:

(in thousands)
2004	$	25,495
2005		27,200
2006		28,806
2007		30,305
2008		31,578
2009 - 2013		180,877

Total	$	324,261

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 31^st as well as the Plan’s target percentages and the permissible range:


	Plan Assets		Target	Permissible

	2003	2002	Percentages	Ranges	Benchmark

Asset Category
Equity securities	50%	50%	50%	45% - 55%	Russell 3000 Index
Debt securities	32%	31%	30%	25% - 35%	Lehman Aggregate
Real Estate	9%	9%	10%	5% - 15%	Wilshire NAREIT Index
Other	9%	10%	10%	5% - 15%	-

Total	100%	100%	100%

The assets of the Company’s PBOP Plan are held in VEBA 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.

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3. Savings Plan

NSTAR also provides a defined contribution 401(k) plan for substantially all employees. Matching contributions (which are equal to 50% of the employees’ deferral up to 8% of compensation) included in the accompanying Consolidated Statements of Income amounted to $9 million in 2003, 2002, and 2001. The plan was amended, effective April 1, 2001, to allow participants the ability to reallocate their investments in the NSTAR Common Share Fund to other investment options. Effective January 1, 2002, consistent with the EGTRRA, the plan was further amended to allow for increased maximum annual pre-tax contributions and additional “catch-up” pre-tax contributions for participants age 50 or older, acceptance of other types of “roll-over” pre-tax funds from other plans and the option of reinvesting dividends paid on the NSTAR Common Share Fund or receiving such dividends in cash. The election to reinvest dividends paid on the NSTAR Common Share fund or receive the dividends in cash is subject to a freeze period beginning seven days prior to the date any dividend is paid. During this period, participants cannot change their election. Dividends are paid to this plan four times a year on February 1, May 1, August 1 and November 1.

Note I. Pension and Postretirement Benefits Other Than Pension (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 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 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 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 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 $13.5 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 $12.7 million of revenue related to carrying charges on the net prepaid balance. This carrying charge will be collected from customers in 2004.

On November 20, 2003, both NSTAR and the Massachusetts Attorney General filed motions with the MDTE for reconsideration of its PAM order. As of the date of this filing, no decision has been made by the MDTE on these matters for reconsideration. NSTAR cannot predict the outcome of these motions, but NSTAR does not believe that the decision will have material impact on its earnings.

Note J. Stock-Based Compensation

The NSTAR 1997 Share Incentive Plan (the Plan) permits a variety of stock and stock-based awards, including stock options and deferred (non-vested) stock to be granted to key employees. The Plan limits the terms of awards to ten years. Subject to adjustment for stock-splits and similar events, the aggregate number of common shares that may be awarded under the Plan is four million as a result of an amendment to the Plan approved by shareholders in 2002 that

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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 2003, 2002 and 2001 was $43.20, $45.24 and $39.70, respectively. 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. During 2001, 97,850 deferred shares and 240,500 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. Historically, the Company has acquired common shares in the open market to meet the level of options exercised.

Stock option activity of the Plan was as follows:

				Weighted				Weighted				Weighted
				Average				Average				Average
	2003			Exercise	2002			Exercise	2001			Exercise
	Activity			Price	Activity			Price	Activity			Price
Options outstanding
at January 1	1,046,869		$	40.14	967,602		$	38.80	918,135		$	39.09
Options granted	324,000		$	43.20	265,000		$	45.24	240,500		$	39.70
Options exercised	(140,667	)	$	30.53	(152,033	)	$	39.92	(47,567	)	$	40.21
Options forfeited	(17,433	)	$	43.56	(33,700	)	$	42.92	(143,466	)	$	41.68

Options outstanding at December 31	1,212,769		$	42.02	1,046,869		$	40.14	967,602		$	38.80

Summarized information regarding stock options outstanding at December 31, 2003:

		Options Outstanding		Options Exercisable
		Weighted
		Average
		Remaining	Weighted		Weighted
		Contractual	Average		Average
Range of	Number	Life	Exercise	Number	Exercise
Exercise Prices	Outstanding	(Years)	Price	Outstanding	Price
$25.75-$26.00	48,400	3.45	$25.75	48,400	$25.75
$39.75-$41.38	268,635	4.26	$40.38	268,635	$40.38
$44.38	166,900	6.40	$44.38	166,900	$44.38
$39.70	153,834	7.40	$39.70	103,068	$39.70
$44.12-$45.33	259,000	8.30	$45.24	85,470	$45.24
$43.20	316,000	9.33	$43.20	-	-

There were 672,473, 614,989, and 546,264 stock options exercisable on December 31, 2003, 2002 and 2001, respectively. The weighted average exercise price of these options exercisable are $40.83, $37.62 and $36.54, respectively.

The stock options granted during 2003, 2002 and 2001 have a weighted average grant date fair value of $3.85, $5.97 and $5.10, respectively. The fair value was estimated using the Black-Scholes option-pricing model with the following weighed average assumptions:

	2003		2002		2001
Expected life (years)	4.0		4.0		4.0
Risk-free interest rate	2.54	%	4.31	%	4.82	%
Volatility	18	%	21	%	21	%
Dividends	4.97	%	4.77	%	5.34	%

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Compensation cost recognized in the accompanying Consolidated Statements of Income for deferred share awards in 2003, 2002 and 2001 was $3,530,719, $2,737,216 and $2,069,000, respectively.

Note K. Capital Stock

1. Common Shares

Common share issuances and repurchases in 2001 through 2003 were as follows:

					Premium on
	Number of		Total		Common
(in thousands)	Shares		Par Value		Shares
Balance at December 31, 2000	53,033	$	53,033	$	876,749
Share Incentive Plan and other	-		-		(3,085	)

Balance at December 31, 2001	53,033		53.033		873,664
Share Incentive Plan	-		-		(2,787	)

Balance at December 31, 2002	53,033		53,033		870,877
Share Incentive Plan	-		-		(4,656	)

Balance at December 31, 2003	53,033	$	53,033	$	866,221

Dividends declared per common share were $2.175, $2.13 and $2.075 in 2003, 2002 and 2001, 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 Shares Outstanding	Redemption Price/Share	December 31, 2003	December 31, 2002
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)		2003			2002
Mortgage Bonds, collateralized by property of
operating subsidiaries:
6.54%, due September 2007	$	5,714		$	7,143
7.04%, due September 2017		25,000			25,000
9.95%, due December 2020		25,000			25,000
7.11%, due December 2033		35,000			35,000
Notes:
7.43%, due March 2003		-			15,000
Variable Rate (1.895% in 2003) due May 2006		150,000			-
9.50%, due December 2004		1,000			2,000
7.62%, due November 2006		20,000			20,000
8.70%, due March 2007		5,000			5,000
9.55%, due December 2007		5,714			7,143
7.70%, due March 2008		10,000			10,000
8.0%, due February 2010		498,663			498,444
9.37%, due January 2012		9,474			10,526
7.98%, due March 2013		25,000			25,000
9.53%, due December 2014		10,000			10,000
9.60%, due December 2019		10,000			10,000
6.924%, due June 2021		105,524			106,518
8.47%, due March 2023		15,000			15,000
Debentures:
6.80%, due March 2003		-			150,000
Floating Rate (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
7.80%, due March 2023		181,000			181,000
Sewage facility revenue bonds, due through 2015		18,248			19,882
Massachusetts Industrial Finance Agency (MIFA) bonds:
5.75%, due February 2014		15,000			15,000
Transition Property Securitization Certificates:
6.45%, due September 2003		-			40,555
6.62%, due March 2005		74,727			103,390
6.91%, due September 2007		170,876			170,876
7.03%, due March 2010		171,624			171,624

		2,212,564			2,304,101
Amounts due within one year		(230,033	)		(212,746	)

Total long-term debt	$	1,982,531		$	2,091,355

On January 14, 2004, Boston Edison gave notice to its Trustee that the entire $181 million aggregate principal amount of its 7.80% Debentures due March 15, 2023 will be called for redemption on March 16, 2004 at a price of 103.36% of the principal amount thereof plus accrued interest. As a result, this Debenture is included under current liabilities in the accompanying Consolidated Balance Sheets at December 31, 2003.

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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 2003 and 2002. The weighted average interest rate of the bonds was 7.375% in 2003 and 2002.

The 5.75% tax-exempt unsecured MIFA bonds due 2014 are redeemable beginning in February 2004 at a redemption price of 102%. The redemption price decreases to 101% in February 2005 and to par in February 2006.

On May 14, 2003, ComElectric entered into a $150 million, three-year variable rate unsecured Term Loan with a group of banks. The rate was set at 1.875% for the initial six months and increased to 1.895% for the second six-month period. The net proceeds were used to repay outstanding short-term debt balances.

The aggregate principal amounts of NSTAR long-term debt (including securitization certificates and sinking fund requirements) due in the five years subsequent to 2003 are approximately $230 million in 2004, $177 million in 2005, $248 million in 2006, $84 million in 2007 and $85 million in 2008.

2. Financial Covenant Requirements

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 $425.4 million and $493.6 million as of December 31, 2003 and 2002, respectively. Boston Edison, as servicing agent for BEC Funding, collected $102.3 million in 2003. These Certificates are non-recourse to Boston Edison.

NSTAR has a credit facility of $175 million that consists of a three year, $175 million revolving credit agreement that expires on November 14, 2005. At December 31, 2003 and 2002, there were no amounts outstanding under this revolving credit agreement. The $175 million credit facility serves as a backup to NSTAR’s $175 million commercial paper program that, at December 31, 2003 and 2002, had $1.5 million and $63.5 million outstanding, respectively. Under the terms of this credit agreement, NSTAR is required to maintain a maximum total consolidated debt to total capitalization ratio of not greater than 65% at all times, excluding Transition Property Securitization Certificates, and excluding Accumulated other comprehensive income (loss) from Common equity, and to maintain a ratio of consolidated earnings before interest and taxes to consolidated total interest expense of not less than 2 to 1 for each period of four consecutive fiscal quarters. Commitment fees must be paid on the total agreement amount. At December 31, 2003 and 2002, NSTAR was in full compliance with all of the aforementioned covenants.

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December 31, 2002. In October 2002, following receipt of the proceeds of its $500 million debt issue, its short-term debt balance was reduced to zero. Under the terms of this agreement, Boston Edison is required to maintain a maximum total debt to capitalization ratio of not greater than 60% at all times, excluding Transition Property Securitization Certificates, and excluding Accumulated other comprehensive income (loss) from Common equity, and to maintain a ratio of consolidated earnings before interest and taxes to consolidated total interest expense of not less than 2 to 1 for each period of four consecutive fiscal quarters. Commitment fees must be paid on the total agreement amount. At December 31, 2003 and 2002, Boston Edison was in full compliance with all of its covenants in connection with its short-term credit facilities.

In addition, ComElectric, Cambridge Electric and NSTAR Gas, collectively, have $165 million available under several lines of credit and had $55.1 million and $135.1 million outstanding under these lines of credit at December 31, 2003 and 2002, respectively. ComElectric and Cambridge Electric have FERC authorization to issue short-term securities from time-to-time on or before November 30, 2004 and June 27, 2004, respectively, with maturity dates no later than November 29, 2005 and June 26, 2005, respectively, in amounts such that the aggregate principal does not exceed $125 million and $60 million, respectively, at any one time. NSTAR Gas is not required to seek approval from FERC to issue short-term debt.

Interest rates on the outstanding borrowings generally are money market rates and averaged 1.28% and 1.89% in 2003 and 2002, respectively. In aggregate, short-term borrowings totaled $239.1 million and $198.6 million at December 31, 2003 and 2002, 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 $16.5 million and $53.4 million for 2003 and 2002, 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, 2003 and 2002 were as follows:

	2003		2002

	Carrying	Fair		Carrying	Fair
(in thousands)	Amount	Value		Amount	Value
Long-term indebtedness
(including current maturities)	$2,212,564	$2,485,190		$2,304,101	$2,422,440

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 2003, 2002 and 2001 include the allocation of NSTAR’s (parent company)

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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.

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 and 2001 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 and $4.9 million, respectively. Effective September 30, 2002, certain chilled water operations were terminated in accordance with its contractual obligations. As part of the 2001 charge, NSTAR’s carrying value of this investment has been written-off entirely. In addition, in 2002 and 2001, NSTAR had reserved for the removal costs of those assets. The net loss for 2002 and 2001 for the unregulated operations segment also includes the impact of non-cash, after-tax charges of $17.7 million and $173.9 million, respectively, or $0.33 and $3.28 per share, related to the write-down of NSTAR’s investment in RCN.

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

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(in thousands)		2003		2002			2001
Operating revenues
Electric utility operations	$	2,335,687	$	2,256,584		$	2,660,719
Gas utility operations		465,208		331,775			397,990
Unregulated operations		113,236		103,214			125,337

Consolidated total	$	2,914,131	$	2,691,573		$	3,184,046




Depreciation and amortization
Electric utility operations	$	202,899	$	210,067		$	197,233
Gas utility operations		18,945		17,643			16,588
Unregulated operations		13,672		11,523			17,128

Consolidated total	$	235,516	$	239,233		$	230,949




Operating income tax expense
(benefit)
Electric utility operations	$	103,697	$	96,117		$	106,349
Gas utility operations		15,948		9,677			14,031
Unregulated operations		1,764		1,319			(6,968	)

Consolidated total	$	121,409	$	107,113		$	113,412




Equity income in
investments accounted for by the
equity method (a)
Electric utility operations	$	2,205	$	2,667		$	2,258




Interest charges
Electric utility operations	$	138,046	$	149,733		$	133,019
Gas utility operations		14,203		14,782			14,505
Unregulated operations		8,496		12,108			31,064

Consolidated total	$	160,745	$	176,623		$	178,588




Segment net income (loss)
Electric utility operations	$	150,249	$	156,169		$	164,015
Gas utility operations		24,441		15,298			21,225
Unregulated operations		6,884		(9,760	)		(187,666	)

Consolidated total	$	181,574	$	161,707		$	(2,426	)




Equity Investments
Electric utility operations	$	15,322	$	19,845		$	22,560




Net expenditures for property
Electric utility operations	$	240,699	$	305,153		$	181,463
Gas utility operations		30,167		28,238			26,900
Unregulated operations		36,789		34,693			21,504

Consolidated total	$	307,655	$	368,084		$	229,867




Segment assets
Electric utility operations	$	5,413,765	$	5,464,152		$	4,509,982
Gas utility operations		679,120		656,473			517,659
Unregulated operations		227,775		217,829			300,550

Consolidated total	$	6,320,660	$	6,338,454		$	5,328,191

(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 Power Purchase Agreements

NSTAR Electric expects to continue to make periodic market solicitations for default service and standard offer power supply consistent with provisions of the Massachusetts Electric Restructuring Act of 1997 (Restructuring Act) and MDTE orders. NSTAR Electric has existing long-term power purchase agreements that are expected to supply approximately 80%-85% of its standard offer service obligations for 2004. NSTAR Electric has contracted with third party suppliers to provide 100% of its standard offer supply obligation through December 31, 2004. In connection with this arrangement, NSTAR Electric has assigned its long-term power purchase agreements to one supplier through December 31, 2004. NSTAR Electric is recovering its payments to suppliers through MDTE approved rates billed to customers. NSTAR Electric’s existing portfolio of long-term power purchase contracts supplied a significant amount of its standard offer (including wholesale) energy requirements in 2003. Also during 2003 and 2002, NSTAR Electric entered into an agreement whereby all of its energy supply entitlements were transferred to an independent energy supplier, following which NSTAR Electric repurchased its energy resource needs from this independent energy supplier for NSTAR Electric’s ultimate sale to its standard offer customers.

Capacity costs of long-term contracts reflect NSTAR Electric’s proportionate share of capital and fixed operating costs of certain generating units. In 2003, these cost 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 2003 was 1,201.4 MW.

Information related to long-term power contracts during 2003 was as follows:

					NSTAR Electric’s Proportionate share (in thousands)
	Range of								Capacity Charge
	Contract	Units of			2003			2003	Obligation
Fuel Type of	Expiration	Capacity			Capacity			Total	Through Contract
Generating Unit	Dates	Purchased			Cost			Cost	Expiration Date
		% Range	Total MW
Natural Gas	2008-2017	11.1-100	720.6	$	144,226		$	394,382	$	1,379,021
Nuclear	2004-2012	2.5-43.5	311.2		(19	)		100,606		494
Refuse	2015	100	76.9		-			57,244		-
Hydro	2014-2023	100	24.7		-			11,996		-
Oil	2005-2019	100	68.0		3,777			4,527		39,328

Total			1,201.4	$	147,984		$	568,755	$	1,418,843

NSTAR Electric’s total capacity and/or energy costs associated with these contracts in 2003, 2002 and 2001 were approximately $569 million, $666 million and $678 million, respectively. NSTAR Electric’s capacity charge obligation under these contracts for the years after 2003 are as follows:

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		Capacity
		Charge
(in thousands)		Obligation
2004	$	137,487
2005		144,011
2006		143,235
2007		147,268
2008		146,635
Years thereafter		700,207

	$	1,418,843

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. 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 2004 to 2014. NSTAR Gas’ firm contract demand charges associated with firm pipeline transportation and storage capacity contracts in 2003, 2002 and 2001 were approximately $50.5 million, $51.8 million and $51.8 million, respectively. NSTAR Gas’ firm contract demand charges at current rates under these contracts for the years after 2003 are as follows:

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		Capacity
		Charge
(in thousands)		Obligation
2004	$	49,909
2005		49,709
2006		46,588
2007		36,832
2008		35,522
Years thereafter		125,803

	$	344,363

Note P. Other Utility Matters

Service Quality Indicators

As of December 31, 2003, NSTAR Electric’s and NSTAR Gas’ 2003 performance has exceeded the applicable established benchmarks such that no liability has been accrued for 2003.

Generating Assets Divestiture

a. Seabrook Nuclear Power Station

On November 1, 2002, FPL Group, Inc. purchased 88% of the majority ownership interest in the Seabrook Nuclear Power Station, including Canal’s 3.52% ownership interest, for $799.4 million, net of closing adjustments. FPL Group assumed responsibility for the ultimate decommissioning of the facility and received the Seabrook decommissioning funds of approximately $226.9 million at the closing. Canal’s portion of the sale proceeds amounted to $31.9 million, of which $3.5 million was paid into the decommissioning trust as a final top-off and $1.3 million was used for other transaction costs. The net proceeds of $27.1 million were less than Canal’s remaining investment in Seabrook. The difference of approximately $16.2 million was included as a component of Cambridge Electric’s and ComElectric’s transition cost recovery and has been collected from ComElectric’s and Cambridge Electric’s customers in 2003 through the transition charge. As part of this sale, all purchased power agreements were terminated. The Seabrook sale did not have an impact on NSTAR’s current results of operations. The future impact of the sale will not have a material effect on NSTAR’s results of operations, cash flow or financial position.

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b. 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 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 will continue to manage the day-to-day operations of the steam plant on this site for one year after the sale.

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 2003 are as follows:


(in thousands)
2004	$	20,979
2005		17,152
2006		13,238
2007		10,454
2008		8,617
Years thereafter		38,885

	$	109,325

The total expense for both lease rentals and transmission agreements was $88.2 million in 2003, 86.6 million in 2002 and $82.7 million in 2001, net of capitalized expenses of $1.9 million in 2003, $2.3 million in 2002 and $2.9 million in 2001.

Total rent expense for all operating leases, except those with terms of a month or less, amounted to $7.6 million in 2003, $9.1 million in 2002 and $10.4 million in 2001.

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, 2004 through June 30, 2004 and for 50% of its obligation, other than to large customers, for the second-half of 2004. NSTAR Electric has entered into a short-term power purchase agreement to meet its entire default service supply obligation for large customers through March 2004. A Request for Proposals will be issued quarterly in 2004 for the remainder of the obligation for large customers and semi-annually for non-large customers in accordance with MDTE regulations. NSTAR Electric entered into agreements ranging in length from six to twelve-months effective January 1, 2003 through December 31, 2003 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.

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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, 2003, NSTAR’s portion of these guarantees amounted to $11.1 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 2003, NEH repurchased a total of 270,000 of its outstanding shares from all equity holders and NHH repurchased a total of 1,075 outstanding shares from all equity holders. Through December 31, 2003, NSTAR Electric’s reduction of its equity ownership resulting from NEH buy-back of 39,061 shares and NHH buy-back of 156 shares was approximately $851,000.

Canal had owned a 3.52% joint ownership interest in the Seabrook Nuclear Power Station (Seabrook) until November 1, 2002. On that date, FPL Group, Inc. purchased an 88% ownership interest in Seabrook, including Canal’s 3.52% ownership interest for $799.4 million, net of closing adjustments. Canal’s portion of the proceeds amounted to $31.9 million, less the $3.5 million paid into the decommissioning trust as a final top-off and $1.3 million for other transaction costs. The net proceeds of $27.1 million were less than Canal’s remaining investment in Seabrook. The net result of this transaction was included as a component of Cambridge Electric’s and ComElectric’s transition cost recovery of approximately $16.2 million and was collected from Cambridge Electric’s and ComElectric’s customers in 2003 through the transition charge. As part of this sale, all purchased power agreements were terminated. This transaction did not have an impact on NSTAR’s current results of operations. The future impact of this transaction will not have a material effect on NSTAR’s operations.

Cambridge Electric had a 2.65% interest in the Vermont Yankee nuclear power plant. On July 31, 2002, Vermont Yankee was sold for approximately $180 million to Entergy Nuclear Vermont Yankee, LLC (Entergy). The sale agreement provided, among other items, that Entergy assume responsibility for the ultimate decommissioning of the facility and received the Vermont Yankee decommissioning funds. Pursuant to the terms of an Additional Power Contract, Cambridge Electric is obligated to purchase its 2.5% entitlement percentage of the output of the plant through the current license term ending in March 2012. The plant’s owners, before the sale, were a consortium of New England utilities, including Cambridge Electric. This transaction did not have an impact on NSTAR’s results of operations or cash flows. The net result of this transaction was included as a component of Cambridge Electric’s transition cost recovery and is reflected on the accompanying Consolidated Balance Sheets as a Regulatory asset.

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

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$14.6 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. These estimates may be revised from time to time based on information available to the Yankee Companies regarding future costs.

The various decommissioning trusts for which NSTAR or it subsidiaries are responsible through their equity ownership are established pursuant to the Code of Federal Regulations, Title 18 - Conservation of Power and Water Resources. The investment of decommissioning funds that have been established, are managed in accordance with these federal guidelines, state jurisdictions and with the applicable Internal Revenue Service requirements. Some of the requirements state that these investments be managed independently by a prudent fund manager and that funds are to be invested in conservative, minimum risk investment securities. Any gains or losses are anticipated to be refunded to or collected from customers, respectively.

3. Financial and Performance Guarantees

At December 31, 2003, outstanding guarantees totaled $32.1 million as follows:

(in thousands)
Letters of Credit	$	5,527
Surety Bonds		15,476
Other Guarantees		11,100

Total Guarantees	$	32,103

The $5.5 million letter of credit is for the benefit of a third party, as trustee in connection with the 6.924% Notes of one of 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, 2003, there have been no amounts drawn under this letter of credit.

NSTAR and its subsidiaries have also issued $11.1 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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4. Environmental Matters

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, 2003 and 2002, NSTAR has recorded a liability of approximately $4.4 million and $4.8 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.

5. Income Tax Matters

On December 24, 2003, NSTAR exited from its investment in RCN and formally abandoned the 11.6 million shares of RCN common stock. The Company will claim an ordinary loss on its 2003 tax return as opposed to a capital loss that would have resulted from a sale of the stock. The Company’s position relative to the tax consequences of the transaction is supported by an opinion from an independent tax advisor.

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.

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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.

The Company believes that its position is well supported. However, if the Company’s position proves incorrect, 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 November 6, 2003, Boston Edison received approval of a Settlement Agreement with the Massachusetts Attorney General (AG) from the MDTE resolving issues in Boston Edison’s reconciliation of costs and revenues for the year 2002. This settlement had a minimal impact to Boston Edison’s results of operation.

Effective September 1, 2003, Boston Edison’s, ComElectric’s and Cambridge Electric’s Standard Offer Service Fuel Adjustment (SOSFA) rates were modified 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. The Boston Edison SOSFA was reduced to zero while the ComElectric and Cambridge Electric SOSFAs were increased to 1.424 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 2002, NSTAR Electric filed proposed transition rate adjustments for 2003, including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2002. The MDTE subsequently approved tariffs for each retail electric subsidiary effective January 1, 2003. The filings were updated in February 2003 to include final costs and revenues for 2002.

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purchased power agreement with Hydro Quebec. As a result of this Settlement Agreement with the AG, Boston Edison recognized approximately $11.4 million in additional transition charge revenues in 2002. This benefit was significantly offset by several other regulatory true-up adjustments.

c. 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 liability will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal liabilities that may result from changes in estimates could have a material impact on its results of operations for a reporting period.

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Report of Independent Auditors

To the Shareholders and Trustees of NSTAR:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) on page 93, present fairly, in all material respects, the financial position of NSTAR and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 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) on page 93, 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 NSTAR’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 auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

PricewaterhouseCoopers LLP

/s/ PRICEWATERHOUSECOOPERS LLP

Boston, Massachusetts

January 20, 2004

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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

NSTAR’s disclosure controls and procedures are designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission.

NSTAR carried out an evaluation, under the supervision and with the participation of NSTAR’s management, including NSTAR’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of NSTAR’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15 as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that NSTAR’s disclosure controls and procedures were effective (1) to timely alert them to material information relating to NSTAR’s information required to be disclosed by NSTAR in the reports that it files or submits under the Securities Exchange Act of 1934 and (2) to ensure that appropriate information is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

During the most recent fiscal quarter, there have been no changes in NSTAR’s internal control over financial reporting that materially affected, or are reasonably likely to materially affect, internal control over financial reporting.

Part III

The information called for by Part III (Items 10(a), 11, 12 (other than Equity Compensation Plan Information), and 14) will be included in NSTAR’s 2004 Proxy Statement (as specified below) to be filed in connection with the annual meeting of shareholders to be held on April 29, 2004 and is incorporated herein by reference. Such Proxy Statement will be filed with the Securities and Exchange Commission (SEC) within 120 days of NSTAR’s fiscal year end of December 31, 2003.

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 2004 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 2004 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 2004 Proxy Statement entitled “Section 16(a) Beneficial Ownership Reporting Compliance.”

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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 2004 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 2004 Proxy Statement entitled “Trustee Compensation,” “Common Share Ownership by Trustees and Executive Officers,” “Compensation Committee Interlocks and Insider Participation” and “Change in Control/Employment Agreements.”

Equity Compensation Plan Information

The following table provides information about NSTAR’s equity compensation plans as of December 31, 2003.

			Number of
	Number of		securities
	securities to be		remaining
	issued upon	Weighted-average	available for
	exercise of	exercise price of	future issuance
	outstanding	outstanding	under equity
Plan Category	options	options	compensation plans

Equity compensation plans
approved by shareholders	1,212,769	$42.02	1,865,169

Equity compensation plans
not approved by shareholders	-	-	-


Total	1,212,769	$42.02	1,865,169

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 2004 Proxy Statement entitled “2002 -2003 Audit and Related Fees.”

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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 2004 Proxy Statement entitled “Audit, Finance and Risk Management Committee Report.”

Part IV

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K

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

1.		Financial Statements:
			Page
Consolidated Statements of Income for the years ended December 31,
2003, 2002 and 2001			49

Consolidated Statements of Comprehensive Income for the years ended
December 31, 2003, 2002 and 2001			50

Consolidated Statements of Retained Earnings for the years ended
December 31, 2003, 2002 and 2001			50

Consolidated Balance Sheets as of December 31, 2003 and 2002			51

Consolidated Statements of Cash Flows for the years ended
December 31, 2003, 2002 and 2001			52

Notes to Consolidated Financial Statements			53

Selected Consolidated Quarterly Financial Data (Unaudited)			14

Report of Independent Auditors			90

2.	Financial Statement Schedules:

Schedule II - Valuation and Qualifying Accounts for the years ended
December 31, 2003, 2002 and 2001			99

3.	Exhibits:

Refer to the exhibits listing beginning below.

(b)	Reports on Form 8-K:

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A report on Form 8-K was filed/furnished on October 23, 2003 that announced NSTAR’s financial and operating results for the third quarter of 2003.

A report on Form 8-K was filed on November 4, 2003 that disclosed the October 31, 2003 receipt of an order from the Massachusetts Department of Telecommunications and Energy authorizing NSTAR to recover its pension and postretirement other than pension expenses through a reconciling rate mechanism.

A report on Form 8-K was filed on December 4, 2003 that disclosed an increased revised estimate from the management of the Connecticut Yankee nuclear unit of the cost to decommission that unit.

A report on Form 8-K was filed on December 24, 2003 that disclosed the abandonment of NSTAR’s entire investment of approximately 11.6 million common shares of RCN Corporation and the recording of a pre-tax charge of $6.8 million.

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)
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)

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		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		Employment Agreement between Thomas J. May and NSTAR dated May 11, 1999 (Annex A to the Joint Proxy Statement/Prospectus in Part I of the Registration Statement of NSTAR on Form S-4, File No. 333-78285)
10.5		Amended and Restated Change in Control Agreement between NSTAR and Thomas J. May dated October 23, 2003 (filed herewith)
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)

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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)
Exhibit 21		Subsidiaries of the Registrant
21.1		Incorporated herein by reference (NSTAR Form 10-K for the year ended December 31, 2002, File No. 1-14768)
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, 2002, 2001 and 2000, as dated 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)

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Exhibit 4		Instruments Defining the Rights of Security Holders, Including Indentures
4.1		Indenture between Boston Edison Company and the Bank of New York (as successor to Bank of Montreal Trust Company)(Form 10-Q for the quarter ended September 30, 1988, File No. 1-2301)
4.11		Votes of the Pricing Committee of the Board of Directors of Boston Edison Company taken March 5, 1993 re 6.80% Debentures due March 15, 2003 and 7.80% debentures due March 15, 2023 (Form 10-K for the year ended December 31, 1992, File No. 1-2301)
4.12		Votes of the Pricing Committee of the Board of Directors of Boston Edison Company taken May 10, 1995 re 7.80% debentures due May 15, 2010 (Form 10-K for the year ended December 31, 1995, File No. 1-2301)
4.13		Votes of the Board of Directors of Boston Edison Company taken October 8, 2002 re $500 million aggregate principal amount of unsecured debentures ($400 million, 4.875% due in 2012 and $100 million, Floating rate due in 2005)(Form 8-K dated October 11, 2002, File No. 1-2301)
Exhibit 10		Material Contracts
10.11		Boston Edison Company and Entergy Nuclear Generation Company Purchase and Sale Agreement dated November 18, 1998 (Form 10-K for the year ended December 31, 1999, File No. 1-2301)
10.12		Boston Edison Company Restructuring Settlement Agreement dated July 1997 (Form 10-K for the year ended December 31, 1997, File No. 1-2301)
		Commonwealth Energy System
Exhibit 10		Power Contracts
10.2.1		New England Power Pool Agreement (NEPOOL) dated September 1, 1971 as amended through August 1, 1977, between NEGEA Service Corporation, as agent for CEL, CEC, NBGEL, and various other electric utilities operating in New England together with amendments dated August 15, 1978, January 31, 1979 and February 1, 1980. (Exhibit 5(c)13 to New England Gas and Electric Association’s Form S-16 (April 1980), File No. 2-64731)
10.2.1.1		Thirteenth Amendment to 10.2.1 as amended September 1, 1981 (refiled as Exhibit 3 to the Parent’s 1991 Form 10-K, File No. 1-7316)
10.2.1.2		Fourteenth through Twentieth Amendments to 10.2.1 as amended December 1, 1981, June 1, 1982, June 15, 1983, October 1, 1983, August 1, 1985, August 15, 1985 and September 1, 1985, respectively (Exhibit 4 to the CES Form 10-Q (September 1985), File No. 1-7316)
10.2.1.3		Twenty-first Amendment to 10.2.1 as amended to January 1, 1986 (Exhibit 1 to the CES Form 10-Q (March 1986), File No. 1-7316)
10.2.1.4		Twenty-second Amendment to 10.2.1 as amended to September 1, 1986 (Exhibit 1 to the CES Form 10-Q (September 1986), File No. 1-7316)

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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)

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SCHEDULE II

VALUATION AND QUALIFYING ACCOUNTS

FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 and 2001

(Dollars in Thousands)

				Additions				Deductions
		Balance at		Provisions						Balance
		Beginning		Charged to				Accounts		At End
Description		of Year		Operations		Recoveries		Written Off		of Year
Allowance for Doubtful Accounts
Year Ended December 31, 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
Year Ended December 31, 2001	$	28,309	$	21,815	$	4,130	$	24,491	$	29,763

Tax Valuation Allowance
Year Ended December 31, 2003	$	52,897	$	-	$	-	$	52,897	$	-
Year Ended December 31, 2002	$	64,499	$	15,384	$	-	$	26,986	$	52,897
Year Ended December 31, 2001	$	-	$	64,499	$	-	$	-	$	64,499

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FORM 10-K

NSTAR

DECEMBER 31, 2003

SIGNATURES

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

		NSTAR

		(Registrant)

Date: March 1, 2004	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 1st day of March 2004.

Signature		Title

/s/ THOMAS J. MAY		Chairman, President, Chief Executive

Thomas J. May		Officer and Trustee

/s/ JAMES J. JUDGE		Senior Vice President, Treasurer

James J. Judge		and Chief Financial Officer

/s/ G.L. COUNTRYMAN		Trustee

Gary L. Countryman

/s/ DANIEL DENNIS		Trustee

Daniel Dennis

/s/ THOMAS G. DIGNAN, JR.		Trustee

Thomas G. Dignan, Jr.

/s/ CHARLES K. GIFFORD		Trustee

Charles K. Gifford

/s/ MATINA S. HORNER		Trustee

Matina S. Horner

Signature		Title

/s/ FRANKLIN M. HUNDLEY		Trustee

Franklin M. Hundley

/s/ PAUL A. LA CAMERA		Trustee

Paul A. La Camera

/s/ SHERRY H. PENNEY		Trustee

Sherry H. Penney

/s/ WILLIAM C. VAN FAASEN		Trustee

William C. Van Faasen

/s/ G. L. WILSON		Trustee

Gerald L. Wilson

[ X ]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2003
	or
[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from to


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)

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

Class	Outstanding at March 1, 2004
Common Shares, $1 par value	53,032,546 Shares

Documents Incorporated by Reference
Sections of NSTAR’s Definitive Proxy Statement for the 2004 Annual Meeting of Shareholders to be held on April 29, 2004
incorporated by reference into Parts I and III of this Form 10-K.

Commission file number	1-14768