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UNITED STATES SECURITIES AND

EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2004

or

For the transition period from                      to                     

Commission file number 1-14768

NSTAR

(Exact name of registrant as specified in its charter)

(617) 424-2000

(Registrant’s telephone number, including area code)

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

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

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

x  Yes    ¨  No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   x

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

x  Yes    ¨  No

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

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

Documents Incorporated by Reference

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

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NSTAR

Form 10-K Annual Report - December 31, 2004

Important Shareholder Information

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

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Part I

(a) General Development of Business

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

(b) Financial Information about Industry Segments

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

(c) Narrative Description of Business

Principal Products and Services

NSTAR Electric

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

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

Retail Electric Rates

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

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

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

Sources and Availability of Electric Power Supply

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

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

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

Wholesale Market Rule Changes

Standard Market Design (SMD)

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

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

Locational Installed Capacity (LICAP)

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

Regional Transmission Organization (RTO)

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

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

NSTAR Gas

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

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

Natural Gas Rates

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

In addition to delivery service rates, NSTAR Gas’ tariffs include a seasonal Cost of Gas Adjustment Clause (CGAC) and a Local Distribution Adjustment Clause (LDAC). The CGAC provides for the recovery of all gas

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

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

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

Gas Supply, Transportation and Storage

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

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

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

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

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

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

Franchises

Through their charters, which are unlimited in time, NSTAR Electric and NSTAR Gas have the right to engage in the business of delivering and selling electricity and natural gas and have powers incidental thereto and are entitled to all the rights and privileges of and subject to the duties imposed upon electric and natural gas companies under Massachusetts laws. The locations in public ways for electric transmission and distribution lines or gas distribution lines and gas distribution pipelines are obtained from municipal and other state authorities who, in granting these locations, act as agents for the state. In some cases the actions of these authorities are subject to appeal to the MDTE. The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature. Under Massachusetts law, no other entity may provide electric or gas delivery service to retail customers within NSTAR’s territory without the written consent of NSTAR Electric and/or NSTAR Gas. This consent must be filed with the MDTE and the municipality so affected.

Unregulated Operations

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

RCN Joint Venture, Investment Conversion and Abandonment

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

Regulation

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

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

Capital Expenditures and Financings

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

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

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

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

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

Seasonal Nature of Business

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

Competitive Conditions

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

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Environmental Matters

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

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

Number of Employees

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

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

Management believes it has satisfactory relations with its employees.

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

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

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

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

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

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

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

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

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

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

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

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

Identification of Executive Officers

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PART II

(a) Market Information

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

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

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

(b) Holders

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

(c) Dividends

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

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

(d) Securities authorized for issuance under equity compensation plans

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

(e) Purchases of equity securities

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

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

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Selected Quarterly Consolidated Financial Data (Unaudited)

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Overview

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

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

Cautionary Statement

The MD&A, as well as other portions of this report, contain statements that are considered forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements may also be contained in other filings with the Securities and Exchange Commission (SEC), in press releases and oral statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe” and other words and terms of similar meaning in connection with any discussion of future operating or financial performance. These statements are based on the current expectations, estimates or projections of management and are not guarantees of future performance. Some or all of these forward-looking statements may not turn out to be what NSTAR expected. Actual results could differ materially from these statements. Therefore, no assurance can be given that the outcomes stated in such forward-looking statements and estimates will be achieved.

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

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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. Other factors in addition to those listed here could also adversely affect NSTAR. This report also describes material contingencies and critical accounting policies and estimates in this section and in the accompanying Notes to Consolidated Financial Statements and NSTAR encourages a review of these Notes.

Critical Accounting Policies and Estimates

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

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

a. Revenue Recognition

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

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

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

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

b. Regulatory Accounting

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

c. Derivative Instruments - Power Contracts

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

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

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

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

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

d. Pension and Other Postretirement Benefits

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

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

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

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

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

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

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

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

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

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

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

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e. Decommissioning Cost Estimates

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

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

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

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

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

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

Asset Retirement Obligations

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

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

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

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

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

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

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

Variable Interest Entities

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

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

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

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

New Accounting Standards

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

Generating Assets Divestiture

Blackstone Station

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

Rate and Regulatory Proceedings

a. Service Quality Indicators

Service quality indicators are established performance benchmarks for certain identified measures of service quality relating to customer service and billing performance, customer satisfaction, and reliability and safety performance for all Massachusetts utilities. NSTAR Electric and NSTAR Gas are required to report annually to the MDTE concerning their performance as to each measure and are subject to maximum penalties of up to two percent of transmission and distribution revenues should performance fail to meet the applicable benchmarks.

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

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

b. Retail Electric Rates

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

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

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

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

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

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

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

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

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

c. Wholesale Market Rule Changes

Standard Market Design (SMD)

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

Locational Installed Capacity (LICAP)

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

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

Regional Transmission Organization (RTO)

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

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

d. Natural Gas Rates

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

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

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

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

Other Legal Matters

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

RCN Abandonment

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

Income Tax Matters

a. RCN Abandonment Tax Treatment

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

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

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

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

b. Tax Valuation Allowance

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

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

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

Results of Operations

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

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2004 compared to 2003

Earnings and Operations Overview

Earnings per common share were as follows:

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

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

Energy sales and weather

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

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

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

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

Operating revenues

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

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Electric revenues

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

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

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

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

Gas revenues

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

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

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

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

Unregulated operations revenues

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

Operating expenses

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

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

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

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

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

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

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

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

Other income, net

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

Other deductions, net

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

Interest charges

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

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

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

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2003 compared to 2002

Earnings and Operations Overview

Earnings per common share were as follows:

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

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

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

Energy sales and weather

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

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

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

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

Operating revenues

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

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Electric revenues

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

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

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

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

Gas revenues

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

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

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

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Unregulated operations revenues

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

Operating expenses

Purchased power costs were $1,329.8 million for 2003 compared to $1,236.3 million in 2002, an increase of $93.5 million, or 8%. The increase is primarily the result of increased sales and the higher costs of fuel, partially offset by the recognition of $29.2 million relating to the deferred standard offer and default service supply costs for current period under-collection of these costs. NSTAR Electric adjusts its rates to collect the costs related to energy supply from customers on a fully reconciling basis. Due to the rate adjustment mechanisms, changes in the amount of energy supply expense have no impact on earnings.

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

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

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

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

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

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

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Other income, net

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

Other deductions, net

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

Interest charges

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

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

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

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

Liquidity and Capital Resources

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

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

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