BOSTON EDISON CO - 10-K Annual Report

Exhibit 31

Rule 13a - 15/15d-15(e) Certifications (filed herewith)

Certification Statement of Chief Executive Officer of Boston Edison pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Certification Statement of Chief Financial Officer of Boston Edison pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Exhibit 32

Section 1350 Certifications (filed herewith)

Certification Statement of Chief Executive Officer of Boston Edison pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Certification Statement of Chief Financial Officer of Boston Edison pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Boston Edison Company

Form 10-K Annual Report - December 31, 2003

	Part I	Page

Item 1.	Business	2
Item 2.	Properties	7
Item 3.	Legal Proceedings	8

	Part II

Item 5.	Market for the Registrant’s Common Stock and Related Stockholder Matters	8
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	8
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	26
Item 8.	Financial Statements and Supplementary Financial Information	28
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	54
Item 9A.	Controls and Procedures	55

	Part IV

Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	55



Signatures		60




Important Shareholder Information

Boston Edison files its Forms 10-K, 10-Q and 8-K reports and other information with the Securities and Exchange Commission (SEC). You may access materials Boston Edison has filed with the SEC on the SEC’s website at www.sec.gov. Boston Edison is subject to 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. These codes and amendments to such codes which are applicable to NSTAR’s executive officers senior officers, senior financial officers or directors can be accessed free of charge on NSTAR’s website at www.nstaronline.com. Copies of Boston Edison’s SEC filings may also be obtained by writing or calling NSTAR’s Investor Relations Department at the address or phone number on the cover of this Form 10-K.

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Part I

Item 1. Business

(a) General Development of Business

Boston Edison Company (“Boston Edison” or “the Company”) is a regulated public utility incorporated in 1886 under Massachusetts law and is a wholly owned subsidiary of NSTAR. NSTAR is an energy delivery company engaged primarily in the transmission and distribution of energy. NSTAR serves approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric customers in 81 communities and 0.3 million gas customers in 51 communities. Boston Edison serves approximately 695,000 electric customers in the City of Boston and 39 surrounding communities. NSTAR’s retail utility subsidiaries are Boston Edison, Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas). NSTAR’s three retail electric companies operate under the brand name “NSTAR Electric.” Reference in this report to “NSTAR” shall mean NSTAR or one or more of its subsidiaries as the context requires. Reference in this report to “NSTAR Electric” shall mean each of Boston Edison, ComElectric and Cambridge Electric. NSTAR has a service company that provides management and support services to substantially all NSTAR subsidiaries - NSTAR Electric & Gas Corporation (NSTAR Electric & Gas).

Harbor Electric Energy Company (HEEC), a wholly owned subsidiary of Boston Edison, provides distribution service and ongoing support to its only customer, the Massachusetts Water Resources Authority’s wastewater treatment facility located on Deer Island in Boston, Massachusetts. Boston Edison’s other wholly owned consolidated special-purpose subsidiary, BEC Funding LLC (BEC Funding), was established to facilitate the sale, on July 29, 1999, of $725 million of electric rate reduction certificates at a public offering. The certificates are secured by a portion of the transition charge assessed on Boston Edison’s retail customers as permitted by the 1997 Massachusetts Electric Restructuring Act (Restructuring Act) and authorized by the Massachusetts Department of Telecommunications and Energy (MDTE). These certificates are non-recourse to Boston Edison.

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

(b) Financial Information about Industry Segments

Boston Edison operates as a regulated electric public utility; therefore industry segment information is not applicable.

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(c) Narrative Description of Business

Principal Products and Services

Boston Edison currently supplies electricity at retail to an area of 590 square miles. The territory served includes the City of Boston and 39 surrounding cities and towns. The population of the area served with electricity at retail is approximately 1.6 million. In 2003, Boston Edison served an average of approximately 695,000 customers. Boston Edison also supplies electricity at wholesale for resale to municipal electric departments. Electric operating revenues by customer class for the last three years consisted of the following:

Retail electric revenues:	2003	2002	2001
Commercial	57%	55%	57%
Residential	34%	33%	31%
Industrial	7%	7%	9%
Other	1%	1%	1%
Wholesale and contract revenues	1%	4%	2%

Retail Electric Rates

Unbundled delivery rates are established by the MDTE and are composed of distribution charges including a fixed customer charge and energy and demand charges (to collect the costs of building and expending the infrastructure to deliver power to its destination, as well as ongoing operating and maintenance costs), a transition charge (to collect costs for previously held investments in generating plants and current costs related to above market power contracts), a transmission charge (to collect the cost of moving the electricity over high voltage lines from a generating plant to substations located within Boston Edison’s service area), an energy conservation charge (to collect costs for demand-side management programs) and a renewable energy charge (to collect the cost to support the development and promotion of renewable energy projects). Beginning in 2004, Boston Edison’s rate was increased to reflect the carrying charge on the average net prepaid pension and postretirement benefit obligations other than pension (PBOP) balances and to recover a portion of the deferred pension and PBOP balances for 2003. Refer to the Consolidated Financial Statements, Note F, for more detail.

Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through either standard offer service or default service for those who choose not to buy energy from a competitive energy supplier. Currently, standard offer service is scheduled to be available to eligible customers through February 2005 at prices approved by the MDTE. The delivery rates and the standard offer service are set at levels so as to guarantee mandatory overall rate reductions required by the Restructuring Act. Currently, new retail customers in the Boston Edison service territory and other customers who are no longer eligible for standard offer service and have not chosen to receive service from a competitive supplier are provided default service. Default service rates are reset every six months (every three months for large commercial and industrial customers). The price of default service is intended to reflect the average competitive market price for power. Boston Edison anticipates that upon the expiration of standard offer service, effective, March 1, 2005, all customers will be eligible for default service. However, Massachusetts’ officials are considering new deregulation legislation to be effective after March 1, 2005. Boston Edison cannot predict or anticipate the outcome of this process or its impact on Boston Edison or its customers. As of December 31, 2003 and 2002, customers of Boston Edison had approximately 27% and 28%, respectively, of their load requirements provided by competitive suppliers.

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Sources and Availability of Electric Power Supply

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

Standard Market Design (SMD)

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

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

Regional Transmission Organization (RTO)

On October 31, 2003, the ISO-NE, responsible for the day-to-day operations of New England’s bulk generation and transmission systems, together with the utility companies that own transmission facilities in New England, filed a proposal with FERC creating a RTO in compliance with FERC directives and pronouncements. It is anticipated that FERC will act on this proposal by March 1, 2004.

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

Franchises

Boston Edison has the right to engage in the business of delivering and selling electricity, has powers incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon electric companies under Massachusetts laws. The locations in public ways for electric transmission and distribution lines are obtained from municipal and other state authorities which, in granting these locations, act as agents for the state. In some cases the actions of these authorities are subject to appeal to the MDTE. The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature. Under Massachusetts law, no other entity may provide electric delivery service to retail customers within Boston Edison’s territory

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without the written consent of Boston Edison which must be filed with the MDTE and the municipality so affected.

Regulation

Boston Edison and its wholly owned regulated subsidiaries, HEEC and BEC Funding, operate primarily under the authority of the MDTE, whose jurisdiction includes supervision over retail rates for distribution of electricity, financing and investing activities. In addition, the FERC has jurisdiction over various phases of Boston Edison’s electric utility business, including rates for electricity 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 2004 through 2008 are as follows:

	2004	2005	2006	2007	2008
(in thousands)
Capital expenditures*	$201,000	$209,000	$219,000	$166,000	$166,000
Long-term debt	$221,765	$170,052	$70,254	$70,170	$70,140

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

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

Net plant expenditures in 2003 were approximately $177 million and consisted primarily of additions to Boston Edison’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 Boston Edison service territory.

Seasonal Nature of Business

Boston Edison 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.

Competitive Conditions

Although under Massachusetts law, no other entity may provide distribution service to retail customers within Boston Edison’s territory without the written consent of Boston Edison, the electric industry, in general, has 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

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

Environmental Matters

Boston Edison is 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 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

Boston Edison does not have any employees. All labor services are provided by employees of NSTAR Electric & Gas. As of December 31, 2003, NSTAR Electric & Gas had approximately 3,100 employees, including approximately 2,300, or 74%, who are represented by two units covered by separate collective bargaining contracts. Local 369 of the Utility Workers Union of America, AFL-CIO, represents approximately 2,000 employees with a contract that expires on May 15, 2005. A labor contract with Local 12004, United Steelworkers of America, AFL-CIO covering 260 employees has a contract that expires on March 31, 2006

Management believes it has satisfactory relations with its employees.

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

Boston Edison delivers electricity to retail and wholesale customers in the Boston area. Boston Edison does not have any foreign operations or export sales.

Item 2. Properties

Boston Edison 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.

Boston Edison’s transmission lines are generally located on land either owned or subject to easements in its favor. Its distribution lines are located principally on public property under permission granted by municipal and other state authorities.

As of December 31, 2003, the primary and secondary overhead and underground distribution system cover approximately 10,900 and 6,000 circuit miles, respectively. In addition, Boston Edison’s transmission system consists of 127 substation facilities and approximately 720,400 active customer meters. HEEC, Boston Edison’s regulated subsidiary, has a distribution system that consists principally of a 4.1 mile 115 kv submarine distribution line and a substation which is located on Deer Island in Boston, Massachusetts. HEEC provides the ongoing support required to distribute electric energy to its one customer, the Massachusetts Water Resources Authority, at this location.

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Item 3. Legal Proceedings

In the normal course of its business, Boston Edison 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, Boston Edison does not believe that it is probable that any such legal liability will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal liabilities that may result from changes in estimates could have a material impact on its results of operations and cash flows for a reporting period.

PART II

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

The information required by this item is not applicable because all of the common stock of Boston Edison is held solely by NSTAR.

Market information for the common shares of NSTAR is included in Item 5 of NSTAR’s Annual Report on Form 10-K for the year ended December 31, 2003.

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

Harbor Electric Energy Company (HEEC), a wholly owned subsidiary of Boston Edison, provides distribution service and ongoing support to its only customer, the Massachusetts Water Resource Authority’s wastewater treatment facility located on Deer Island in Boston, Massachusetts. Boston Edison’s other wholly owned consolidated special-purpose subsidiary, BEC Funding LLC (BEC Funding), was established to facilitate the sale, on July 29, 1999, of $725 million of electric rate reduction certificates at a public offering. The certificates are secured by a portion of the transition charge assessed on Boston Edison’s retail customers as permitted by the 1997 Massachusetts Electric Restructuring Act (Restructuring Act) and authorized by the Massachusetts Department of Telecommunications and Energy (MDTE). These certificates are non-recourse to Boston Edison.

Boston Edison generates its revenues primarily from the sale of energy, distribution and transmission services to customers. However, Boston Edison’s earnings are impacted by fluctuations in unit sales of kilowatt-hours, which directly determine the level of distribution and

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transmission revenues recognized. In accordance with the regulatory rate structure in which Boston Edison 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 expense but will not affect the Company’s earnings.

Cautionary Statement

The MD&A, as well as other portions of this report, contain statements that are considered forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements may also be contained in other filings with the Securities and Exchange Commission (SEC), in press releases and oral statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “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 Boston Edison expected. Actual results could differ materially from these statements. Therefore, no assurance can be given that the outcomes stated in such forward-looking statements and estimates will be achieved.

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

-	impact of continued cost control procedures on operating results
-	weather conditions that directly influence the demand for electricity
-	changes in tax laws, regulations and rates
-	financial market conditions including, but not limited to, changes in interest rates and the availability and cost of capital
-	prices and availability of operating supplies
-	prevailing governmental policies and regulatory actions (including those of the MDTE and Federal Energy Regulatory Commission (FERC) with respect to allowed rates of return, rate structure, continued recovery of regulatory assets, financings, purchased power, acquisition and disposition of assets, operation and construction of facilities, changes in tax laws and policies and changes in, and compliance with, environmental and safety laws and policies

-	changes in financial reporting standards
-	new governmental regulations or changes to existing regulations that impose additional operating requirements or liabilities
-	changes in specific hazardous waste site conditions and the specific cleanup technology
-	impact of uninsured losses

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

-	future economic conditions in the regional and national markets

-	ability to maintain current credit ratings, and

-	the impact of terrorist acts

Any forward-looking statement speaks only as of the date of this filing and Boston Edison 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 Boston Edison makes in its filings to the SEC. Also note that Boston Edison provides in the above paragraphs a cautionary discussion of risks and other uncertainties relative to its business. These are factors that could cause its actual results to differ materially from expected and historical performance. Other factors in addition to those listed here could also adversely affect Boston Edison. 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 Boston Edison encourages a review of these Notes.

Critical Accounting Policies and Estimates

Boston Edison’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. Boston Edison believes that its accounting policies and estimates that are most critical to the reported results of operations, cash flows and financial position are described below.

a. Revenue Recognition

Utility revenues are based on authorized rates approved by the MDTE and FERC. Estimates of distribution and transition revenues for electricity delivered to customers but not yet billed are accrued at the end of each accounting period. The determination of unbilled revenues requires management to estimate the volume and pricing of electricity delivered to customers prior to actual meter readings.

Revenues related to the sale, transmission and distribution of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters that are read on a systematic basis throughout the month. Meters which are not read during a given month are estimated and trued-up in a future period. At the end of each month, amounts of energy

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delivered to customers since the date of the last billing date are estimated and the corresponding unbilled revenue is estimated. This unbilled electric revenue is estimated each month based on daily generation volumes (territory load), estimated line losses and applicable customer rates. Accrued unbilled revenues recorded in the accompanying Consolidated Balance Sheets as of December 31, 2003 and 2002 were $21.9 million and $21.5 million, respectively.

The level of unbilled revenue is subject to seasonal weather conditions. Electric sales volumes are typically higher in the winter and summer than in the spring or fall. As a result, Boston Edison records a higher level of unbilled revenue during the seasonal periods mentioned above.

b. Regulatory Accounting

Boston Edison follows accounting policies prescribed by GAAP, the FERC and the MDTE. As a rate-regulated company, Boston Edison is 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. Boston Edison’s energy delivery business remains subject to rate-regulation and continues to meet the criteria for application of SFAS 71. This ratemaking process results in the recording of regulatory assets based on the probability of current and future cash inflows. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery from customers. As of December 31, 2003 and 2002, Boston Edison has recorded regulatory assets of $1.1 billion and $1.3 billion, respectively. This decrease is primarily the result of the collection of regulatory generation-related assets secured by securitization certificates and costs to achieve the 1999 merger from customers and retiree benefit costs as a result of a lower additional minimum liability adjustment. Boston Edison continuously reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Boston Edison expects to fully recover these regulatory assets in its rates. If future recovery of costs ceases to be probable, Boston Edison would be required to charge these assets to current earnings. However, impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Regulatory assets related to the generation business are recovered through the transition charge.

c. Derivative Instruments - Power Contracts

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

Boston Edison has long-term purchased power agreements that are used primarily to meet its standard offer obligation. The majority of these agreements are above-market but are not reflected on the accompanying Consolidated Balance Sheets as they qualify for the normal purchases and sales exception. However, in Issue C15, the DIG concluded that contracts with a pricing mechanism that are subject to future adjustment based on a generic index that is not specifically related to the contracted service commodity generally would not qualify for the normal purchases and sales exception. Boston Edison has one purchased power contract that contains components with pricing mechanisms that are based on a pricing index, such as the Gross

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National Product or Consumer Price Index. Although these factors are only applied to certain ancillary pricing components of this agreement, as required by the interpretation of DIG Issue C15, Boston Edison began recording this contract at fair value on its Consolidated Balance

Sheets during 2002. As a result, the recognition of a liability for the fair value of the above-market portion of this contract at December 31, 2003 is approximately $271 million and is reflected as a component of Deferred credits - - Power contracts on the accompanying Consolidated Balance Sheets.

This contract is valued using a discounted cash flow model and a 10% discount rate. The market value assumption used was provided by a third party who determines such pricing for the New England power market. Had management used an alternative assumption, the value of this contract at December 31, 2003 would have changed significantly. A one percent increase or decrease to the discount rate would change the above market value by approximately $14 million from what is presently recorded.

Boston Edison recovers all of its electricity supply costs, including the above-market costs from customers. For this one purchase power agreement, the recovery of its above-market costs occurs through 2013. This recovery period coincides with the contractual terms of this purchased power agreement. Therefore, in addition to the liability recorded, Boston Edison also recorded a corresponding regulatory asset representing the future recovery of this actual cost. As a result, any changes to the fair value of this contract will not have an effect on Boston Edison’s earnings.

d. Pension and Other Postretirement Benefits

Boston Edison is the sponsor of NSTAR’s qualified Pension Plan (the Plan). As its sponsor, Boston Edison allocates the costs of the Plan to NSTAR Electric & Gas. NSTAR Electric & Gas charges all of its benefit costs to the NSTAR operating companies, including Boston Edison, on a percentage of total direct labor charged to the Company.

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

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

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

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The Plan’s assets, which partially consist of equity investments, were affected by significant declines in the financial markets from 2000 through 2002 despite positive investment performance during 2003. Fluctuations in market returns may result in increased or decreased

pension costs in future periods. These conditions impacted the funded status of the Plan at both December 31, 2003 and 2002, and therefore, will also impact pension costs for 2004.

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

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

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

NA - not applicable

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

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

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

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

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On October 31, 2003, the MDTE approved Boston Edison’s request for a reconciliation rate adjustment mechanism related to pension and PBOP costs. As part of this ruling, which effectuated a 2002 MDTE Accounting Order, Boston Edison is allowed to record a regulatory asset in lieu of taking a charge to OCI for the additional minimum liability requirement for under-funded benefit plans. As of December 31, 2003 and 2002, Boston Edison has recorded a regulatory asset of $172.9 million and $262.6 million, respectively. The regulatory asset is shown as part of Deferred debits in the accompanying Consolidated Balance Sheets.

The Plan currently meets the minimum funding requirements of the Employee Retirement Income Security Act of 1974. While not required to make contributions to the Plan, Boston Edison anticipates that it will contribute approximately $40 million to the Plan in 2004. Boston Edison believes it has adequate access to capital resources to support these contributions.

e. Decommissioning Cost Estimates

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

While Boston Edison no longer directly owns any nuclear power plants, Boston Edison owns, through its equity investments, 9.5% of Connecticut Yankee Atomic Power Company (CYAPC) and 9.5% of Yankee Atomic Electric Company (YAEC), (the “Yankee Companies”). Periodically, Boston Edison obtains estimates from the management of the Yankee Companies on the cost of decommissioning the Connecticut Yankee nuclear unit (CY) and the Yankee Atomic nuclear unit (YA). These nuclear units are completely shut down and are currently conducting decommissioning activities.

Based on estimates from the Yankee Companies’ management as of December 31, 2003, the total remaining cost for decommissioning each nuclear unit is approximately as follows: $666.4 million for CY and $181.3 million for YA. Of these amounts, Boston Edison is obligated to pay $63.3 million towards the decommissioning of CY and $17.2 million toward YA. These estimates are recorded in the accompanying Consolidated Balance Sheets as Power contract liabilities with a corresponding regulatory asset and do not impact the current results of operations. These estimates may be revised from time to time based on information available to the Yankee Companies regarding future costs.

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

Asset Retirement Obligations

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

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Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

Boston Edison 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.

Boston Edison has also 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, Boston Edison 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 Boston Edison, cost of removal (negative net salvage) is recognized as a component of depreciation expense in accordance with approved regulatory treatment. Cost of removal was previously included in accumulated deprecation but is currently reflected as a regulatory liability in conjunction with the adoption of SFAS 143. As of December 31, 2003 and 2002, the estimated amount of the cost of removal included in regulatory liabilities was approximately $123 million and $145 million, respectively, based on the cost of removal component in current depreciation rates.

New Accounting Standards

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

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

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

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In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities”, as amended and revised in December 2003 (FIN 46R), which addresses the

consolidation of variable interest entities (VIE’s) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise with the majority of the risks or rewards associated with the VIE. Application of this Interpretation is required for all potential VIE’s that are referred to as special-purpose entities for periods ending after December 15, 2003 and, for all other types of entities that are potential VIE’s that are not referred to as special purpose entities, the consolidation requirements apply for periods ending after March 15, 2004. Boston Edison has assessed the impact of FIN 46R and has determined that Boston Edison does have a VIE for which Boston Edison is the primary beneficiary requiring consolidation of the entity as of December 31, 2003. For all other types of entities, Boston Edison is still assessing the impact that FIN 46R will have on its consolidated financial position.

Boston Edison has a wholly owned special purpose subsidiary, BEC Funding LLC, established to facilitate the sale and administration of $725 million in notes to a special purpose trust created by two Massachusetts state agencies. Historically, Boston Edison has consolidated this entity. As part of Boston Edison’s assessment of FIN 46R, Boston Edison reviewed the substance of this entity to determine if it is still proper to consolidate this entity. Based on its review, Boston Edison has concluded that BEC Funding LLC is a variable interest entity and should continue to be consolidated by Boston Edison.

Rate and Regulatory Proceedings

a. Goodwill and Costs to Achieve

The merger that created NSTAR was accounted for using the purchase method of accounting. In accordance with Accounting Principles Board (APB) No. 16 - “Business Combinations,” all goodwill was recorded on the books of the subsidiaries of COM/Energy. However, under the merger rate plan approved by the MDTE, all of NSTAR’s utility subsidiaries share in the recovery of goodwill in their rates. As a result, goodwill amortization expense is allocated to Boston Edison from ComElectric, Cambridge Electric and NSTAR Gas through an intercompany charge. The Company is currently recovering these amounts in its rates.

NSTAR recorded goodwill associated with the merger of BEC Energy and COM/Energy of approximately $490 million, resulting in an annual amortization of goodwill of approximately $12.2 million. Boston Edison was allocated $319 million of goodwill and is expensing this amount. This amount is being recovered in Boston Edison’s rates and is treated as an intercompany charge among the Company and its affiliated companies, ComElectric, Cambridge Electric and NSTAR Gas. This treatment results in differences in equity balances between GAAP and equity balances used for regulatory purposes. Costs to achieve (CTA) are being amortized based on the filed estimate of $111 million over 10 years. CTA are the costs incurred to execute the merger including the employee costs for a voluntary severance program, costs of financial advisors, legal costs and other transaction and systems integration costs. These amounts are expected to be offset by ongoing costs savings from streamlined operations and avoidance of costs that would have otherwise been incurred by BEC and COM/Energy. For the year ended December 31, 2003, Boston Edison’s portions of goodwill and CTA amortization were approximately $8 million and $7.2 million, respectively. NSTAR’s retail utility subsidiaries will reconcile the actual CTA costs incurred with the original estimate in a future rate proceeding and any difference is expected to be recovered over the remainder of the amortization period. This reconciliation will include a final accounting of the deductibility for income tax purposes of each component of CTA.

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The total CTA is approximately $143 million of which approximately $93 million has been allocated to Boston Edison. This increase from the original estimate for NSTAR is partially

mitigated by the fact that the portion of CTA that is not deductible for income tax purposes is approximately $20 million lower than the original estimate. Effective upon completion of the four-year rate freeze on August 25, 2003, the CTA amortization expense was increased to reflect the actual CTA expenditures incurred. As a result, the total CTA amortization for Boston Edison was approximately $8.4 million, an increase of $1.2 million from 2002. Boston Edison anticipates that these incremental costs are probable of recovery in future rates.

b. Service Quality Indicators

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

On February 28, 2003, Boston Edison filed its 2002 Service Quality Reports with the MDTE that reflected significant improvements in reliability and performance; the reports indicate that no penalty was assessed for 2002. The MDTE concurred with Boston Edison’s determination in an order issued on September 30, 2003. Boston Edison monitors its service quality continuously to determine its contingent liability, and if it were determined that a liability has been incurred and is estimable, an appropriate liability would be accrued. Annually, Boston Edison makes a service quality performance filing with the MDTE. Any settlement or rate order that would result in a different liability level from what has been accrued would be adjusted in the period an agreement is reached with the MDTE.

As of December 31, 2003, Boston Edison’s 2003 performance has exceeded the applicable established benchmarks such that no liability has been accrued for 2003.

c. Retail Electric Rates

Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through either standard offer or default service for those who choose not to buy energy from a competitive energy supplier. Currently, standard offer service is scheduled to be available to eligible customers through February 2005 at prices approved by the MDTE. The delivery rates and the standard offer service are set at levels so as to guarantee mandatory overall rate reductions required by the Restructuring Act. Currently, new retail customers in the Boston Edison service territory and other customers who are no longer eligible for standard offer service and have not chosen to receive service from a competitive supplier are provided default service. Default service rates are reset every six months (every three months for large commercial and industrial customers). The price of default service is intended to reflect the average competitive market price for power. Boston Edison anticipates that upon the expiration of standard offer service, effective March 1, 2005, all customers will be eligible for default service. However, Massachusetts officials are considering new deregulation legislation to be effective after March 1, 2005. Boston Edison cannot predict or anticipate the outcome of this process or its impact on Boston Edison or its customers. As of December 31, 2003 and 2002, customers of Boston Edison had approximately 27% and 28%, respectively, of their load requirements provided by competitive suppliers.

In December 2003, Boston Edison filed proposed transition rate adjustments for 2004, including a preliminary reconciliation of transition, transmission, standard offer and default service costs and

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revenues through 2003. The MDTE subsequently approved tariffs effective January 1, 2004. The filings were updated in February 2004 to reflect final 2003 costs and revenues which are subject to final reconciliation.

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

Effective September 1, 2003, Boston Edison’s Standard Offer Service Fuel Adjustment (SOSFA) rates were modified upon approval by the MDTE. The MDTE has allowed companies to adjust prices to reduce deferred cost balances that arise due to rapidly changing market costs for the oil and natural gas used to generate electricity and the SOSFA is designed to collect the costs of fuel that companies incur for purchasing electricity from their suppliers to serve their standard offer service customers. The Boston Edison SOSFA was reduced to zero. This change followed an increase in this rate adjustment from zero to 0.902 cents per kilowatt-hour that was effective May 1, 2003. The SOSFA was at zero from April 1, 2002 through April 30, 2003. The MDTE has ruled that these fuel index adjustments are excluded from the 15% rate reduction requirement under the Restructuring Act.

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

In December 2002, Boston Edison filed proposed transition rate adjustments for 2003, including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2002. The MDTE subsequently approved tariffs for Boston Edison effective January 1, 2003. The filing was updated in February 2003 to include final costs and revenues for 2002.

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

d. Standard Market Design (SMD)

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New England: Northeastern MA (NEMA) and Southeastern MA (SEMA). The majority of Boston Edison is located with NEMA. NEMA is import constrained and SEMA is export constrained. At times NEMA has higher priced generation than SEMA. As part of the SMD, load-serving entities, like Boston Edison, were granted proceeds from the auction of “financial transmission rights” that is conducted by ISO-NE. Boston Edison can either use these proceeds to mitigate costs to

customers directly or transfer them to the suppliers of its energy resource needs to reduce the cost to customers.

e. Regional Transmission Organization (RTO)

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

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Other Legal Matters

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

Results of Operations

The following section of MD&A compares the results of operations for each of the two fiscal years ended December 31, 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.

2003 compared to 2002

Energy sales and weather

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

	Years ended December 31,

		2003	2002	% Change
Retail Electric Sales - MWH
Residential		4,238,136	3,996,622	6.0%
Commercial		9,149,003	8,931,442	2.4%
Industrial		1,296,462	1,378,062	(5.9)%
Other		277,942	272,556	2.0%

Total retail sales		14,961,543	14,578,682	2.6%

The 2.6% increase in retail MWH sales in 2003 reflects, by customer sectors, an improvement of 6.0% in residential and 2.4% in commercial offset somewhat by the continued sales decline of 5.9% in the industrial sector. In terms of customer sectors, industrial sales are less sensitive to weather while residential and commercial sales are influenced by temperature extremes. In addition to unseasonably cold winter weather and cool spring and summer conditions in 2003, the increase in sales is attributable in part to further home and commercial building and expansion of existing units and the resulting extension of residential and commercial energy uses. Residential and commercial customers were approximately 28% and 61%, respectively, of Boston Edison’s total retail sales mix for 2003, and provided 34% and 57% of total 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.

Boston Edison forecasts its electric sales based on normal weather conditions. Actual results may differ from those projected due to actual weather conditions above or below these normal weather levels and other factors. Refer to “Cautionary Statement” in this section. Unit sales of electricity in 2004 are expected to grow at approximately 1.5% to 2%.

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			Normal
			30-Year
	2003	2002	Average


Heating degree-days	6,028	5,279	5,630
Percentage change from prior year	14.2%	0.7%
Percentage change from 30-year average	7.1%	(6.2)%

Cooling degree-days	755	972	777
Percentage change from prior year	(22.3)%	18.2%
Percentage change from 30-year average	(2.8)%	25.1%

Weather conditions impact electric sales in Boston Edison’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 2.6% from 2002 as follows:

(in thousands)						Increase/(Decrease)
		2003		2002		Amount		Percent

Electric retail revenues	$	1,594,681	$	1,512,997	$	81,684		5.4
Electric wholesale revenues		19,565		56,578		(37,013	)	(65.4)
Other revenues		84,938		86,583		(1,645	)	(1.9)

Total revenues	$	1,699,184	$	1,656,158	$	43,026		2.6

Electric retail revenues were $1,594.7 million in 2003 compared to $1,513.0 million in 2002, an increase of $81.7 million, or 5.4%. 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 electric retail revenues primarily reflects the 2.6% increase in retail MWH sales. Retail electric revenues also include approximately $9.8 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.

Boston Edison’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 Boston Edison’s residential and small commercial customers. Economic conditions affect Boston Edison’s large commercial and industrial customers.

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Also included in electric retail revenues are 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. However, the retail revenues related to standard offer and default services are fully reconciled to the costs incurred and have no impact on Boston Edison’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.

Electric wholesale revenues were $19.5 million in 2003 compared to $56.6 million in 2002, a decrease of $37.1 million, or 65.5%. 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, Boston Edison 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 will expire resulting in a further decline in wholesale revenues and sales.

Other revenues were $84.9 million in 2003 compared to $86.6 million in 2002, a decrease in $1.7 million or 2.0%. The decrease in other revenues is due to lower rental revenues from energy capacity produced by transmission-related investments, partly offset by higher transmission grid usage by other utility companies in the regional network.

Operating expenses

Purchased power costs were $874.4 million in 2003 compared to $822.4 million in 2002, an increase of $52.0 million, or 6.3%. The increase is primarily the result of increased sales and the higher cost of fuel, partially offset by the deferral of $4.6 million relating to standard offer and default service supply costs for current period under-collection of these costs. Boston Edison 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. In 2002, Boston Edison recognized $14.5 million of costs related to these rate adjustment mechanisms.

Operations and maintenance expense was $224.9 million in 2003 compared to $228.7 million in 2002, a decrease of $3.8 million, or 1.7%. The decrease is primarily due to the overall decrease in maintenance expense of $8.4 million in connection with improvements made in electric distribution service in 2002. In addition, bad debt expense decreased $3.5 million due to the overall improvements in collections. Offsetting this decrease in expense was an overall increase of $11.4 million in pension and PBOP costs. This increase was somewhat mitigated, effective September 1, 2003, as a result of a MDTE order, which allowed Boston Edison to defer approximately $2.4 million through December 31, 2003 of the increase pension and other postretirement benefits expense. Refer to “Rate and Regulatory Proceedings” in this MD&A for further discussion.

DSM and renewable energy programs expense was $45.5 million in 2003 compared to $48.6 million in 2002, a decrease of $3.1 million, or 6.3%, which was consistent with the collection of conservation 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. Therefore, fluctuations in program costs have no impact on earnings.

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Property and other taxes were $72.2 million in 2003 compared to $70.1 million in 2002, an increase of $2.1 million, or 3.0%. This increase was due to higher overall municipal property taxes caused primarily by higher property assessments, capital additions, and tax rates in the City of Boston. The increase was offset by slightly lower payroll charges.

Income taxes attributable to operations were $90.0 million in 2003 compared to $90.5 million in 2002, a decrease of $0.5 million, or less than 1%, reflecting lower pre-tax operating income.

Other income, net

Other income, net was $2.4 million in 2003 compared to $4.0 million in 2002, a decrease of $1.6 million or 40.0%. The decrease was primarily due to a settlement receipt in 2002 on a land purchase and a decline in interest income on securitization costs.

Interest charges

Interest on long-term debt and transition property securitization certificates was $85.4 million in 2003 compared to $85.0 million 2002, an increase of $0.4 million, or less than 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 prices at three month LIBOR plus 50 basis points (1.65% at December 31, 2003). This debt issuance increased interest expense by $16.6 million in 2003. Partially offsetting these increases was the absence in 2003 of $9.1 million in interest due to Boston Edison’s early redemption of its $60 million 8.25% Debentures in September 2002, its $150 million 6.80% Debentures retired in March 2003 and the scheduled repayments of its transition property securitization certificates that resulted in reduced interest expense of $16.0 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 $7.8 million in 2003 compared to $10.8 million in 2002, a decrease of $3.0 million, or 27.8%. This decrease is primarily attributable to lower borrowing rates. The average level of short-term debt outstanding averaged $149.9 million and $142.0 million, however, the interest rate on these borrowings averaged 1.20% and 1.38% in 2003 and 2002, respectively. This decrease was offset by higher regulatory interest charges incurred related to higher deferred transition costs.

Allowance for funds used during construction was $1.2 million in 2003 compared to $1.6 million in 2002, a decrease of $0.4 million or 25%, primarily due to lower average balance of construction work in progress during the year.

Other Events

NSTAR has commenced the regulatory filing process to obtain approval to construct a 345 kv transmission line from the southern suburbs of Boston to South Boston in order to assure continued reliability of service and improve power input capacity in the Northeast Massachusetts area (NEMA). If approved, construction is estimated to begin in the fourth quarter of 2004 and the new transmission line is anticipated to be placed in service during the summer of 2006. This project is a regional transmission investment and, as a result, the cost will be shared by all of New England. This proposed plan is subject to siting and license requirements.

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Performance Assurances from Electricity Agreements

Boston Edison has contracted with a third party supplier to provide 100% of its standard offer service supply obligations through December 31, 2004. In addition, Boston Edison has entered into a number of short-term power purchase agreements to meet its entire default service supply obligation, other than large customers, for the period January 1, 2004 through June 30, 2004 and for 50% of its obligation, other than large customers, for the second half of 2004. Boston Edison has entered into a number of short-term power purchase agreements to meet its entire default service supply obligation for large customers through March 2004. These agreements are for a

term of three to twelve months. Boston Edison currently is recovering payments it is making to suppliers from its customers. All of Boston Edison’s power suppliers are subsidiaries of larger companies with investment grade or better credit ratings. In accordance with Boston Edison’s Internal Credit Policy, and to minimize Boston Edison risk in the event the supplier encounters financial difficulties or otherwise fails to perform, Boston Edison has financial assurances and guarantees that include both Parental Guarantees and letters of credit in place with the parent company of the supplier. In addition, under these agreements, in the event that the supplier (or its parent guarantor) fails to maintain an investment grade credit rating, it is required to provide additional security for performance of its obligations. Boston Edison’s policy is to enter into power supply arrangements only if the supplier (or its parent guarantor) has an investment grade or better credit rating. In view of current volatility in the energy supply industry, Boston Edison is unable to determine whether its suppliers (or their parent guarantors) will become subject to financial difficulties, or whether these financial assurances and guarantees are sufficient. In the event the supplier (or its guarantor) does not provide the required additional security within the required time frames, Boston Edison may then terminate the agreement. In such event, Boston Edison may be required to secure alternative sources of supply at higher or lower prices than provided under the terminated agreements. Some of these agreements include a reciprocal provision, where in the event that a Boston Edison distribution company receives a credit rating below investment grade, that company could be required to provide additional security for performance, such as a letter of credit.

Financial and Performance Guarantees

On a limited basis, Boston Edison may enter into agreements providing financial assurance to third parties. Such agreements include surety bonds and other guarantees.

At December 31, 2003, outstanding guarantees totaled $15.1 million as follows:

(in thousands)
Surety Bonds	$	6,720
Other Guarantees		8,400

Total Guarantees	$	15,120

As of December 31, 2003, Boston Edison has purchased a total of $0.3 million of performance surety bonds for the purpose of obtaining licenses, permits and rights-of-way in various municipalities. In addition, Boston Edison has purchased $6.4 million in workers’ compensation self-insurer bonds. These bonds support the guarantee by Boston Edison to the Commonwealth of Massachusetts required as part of Boston Edison’s workers’ compensation self-insurance program.

Boston Edison has also issued $8.4 million of residual value guarantees related to its equity interest in the Hydro-Quebec transmission companies.

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

Contingencies

Environmental Matters

As of December 31, 2003, Boston Edison is involved in 4 state regulated properties (“Massachusetts Contingency Plan, or “MCP” sites”) where oil or other hazardous materials were previously spilled or released. Boston Edison is required to clean up or otherwise remediate these properties in accordance with specific state regulations. There are sometimes uncertainties associated with total remediation costs due to the final selection of the specific cleanup technology and the particular characteristics of the different sites. Estimates of approximately $0.2 million and $0.4 million are included as liabilities in the accompanying Consolidated Balance Sheets at December 31, 2003 and 2002, respectively.

In addition to the MCP sites, Boston Edison also faces possible liability as a result of involvement in 8 multi-party disposal sites or third party claims associated with contamination remediation. Boston Edison generally expects to have only a small percentage of the total potential liability for these sites. Estimates of approximately $3.4 million and $3.3 million are included as liabilities in the accompanying Consolidated Balance Sheets at December 31, 2003 and 2002, respectively.

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

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

Interest Rate Risk

Boston Edison is exposed to changes in interest rates primarily based on levels of short-term debt outstanding. The weighted average interest rates for long-term indebtedness, including current maturities were 5.71% and 6.19% in 2003 and 2002, respectively. Carrying amounts and fair values of long-term indebtedness (excluding notes payable, including current maturities) as of December 31, 2003 and 2002, were as follows:

	2003		2002

	Carrying	Fair		Carrying	Fair
(in thousands)	Amount	Value		Amount	Value
Long-term indebtedness	$1,256,475	$1,373,110		$1,477,326	$1,480,510
(including current maturities)

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Although Boston Edison has material commodity purchase contracts, these instruments are not subject to market risk. Boston Edison has ratemaking mechanisms that allow for the recovery of fuel costs from customers. Boston Edison customers have the option of continuing to buy power at standard offer prices through February 2005. The cost of providing standard offer service includes fuel and purchased power costs. Default service is the electricity that is supplied by the local distribution company when a customer is not receiving power from standard offer service. The market prices for standard offer and default service will fluctuate based on the average market price for power. Amounts collected through standard offer and default service are recovered on a fully reconciling basis.

In addition, Boston Edison’s exposure to financial market risk results primarily from fluctuations in interest rates. On October 15, 2002, Boston Edison issued $100 million of 3-year floating rate debentures priced at LIBOR plus 50 basis points. An immediate change of one percent for these variable rate debentures would cause a change in interest expense of approximately $1 million per year.

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Report of Independent Auditors

To the Shareholder and Directors of Boston Edison Company:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) on page 55, present fairly, in all material respects, the financial position of Boston Edison Company and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) on page 55, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of Boston Edison’s management; our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

PricewaterhouseCoopers LLP

/s/ PRICEWATERHOUSECOOPERS LLP

Boston, Massachusetts
January 20, 2004

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Item 8. Financial Statements and Supplementary Financial Information

Boston Edison Company
Consolidated Statements of Income

		Years ended December 31,

		2003			2002			2001
		(in thousands)

Operating revenues	$	1,699,184		$	1,656,158		$	1,952,950


Operating expenses:
Purchased power		874,441			822,445			1,129,955
Operations and maintenance		224,869			228,666			203,320
Depreciation and amortization		170,924			170,932			167,905
Demand side management and
renewable energy programs		45,512			48,579			47,639
Taxes-property and other taxes		72,174			70,077			69,777
Income taxes		89,957			90,487			93,967

Total operating expenses		1,477,877			1,431,186			1,712,563


Operating income		221,307			224,972			240,387


Other income:
Other income, net		2,374			4,008			8,154
Other deductions, net		(801	)		(736	)		(224	)

Total other income, net		1,573			3,272			7,930


Interest charges:
Long-term debt		52,684			47,867			45,994
Transition property securitization		32,715			37,135			41,475
Short-term and other		7,775			10,769			11,467
Allowance for borrowed funds used
during construction (AFUDC)		(1,212	)		(1,630	)		(972	)

Total interest charges		91,962			94,141			97,964


Net income	$	130,918		$	134,103		$	150,353

Per share data is not relevant because Boston Edison Company’s common stock is wholly owned by NSTAR.

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

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Boston Edison Company
Consolidated Statements of Comprehensive Income

		Years ended December 31,

		2003		2002		2001
		(in thousands)

Net income	$	130,918	$	134,103	$	150,353
Other comprehensive income, net:
Non-qualified benefit obligations		-		-		195
Deferred income taxes		-		-		(78	)

Comprehensive income	$	130,918	$	134,103	$	150,470

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

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Boston Edison Company
Consolidated Statements of Retained Earnings

		Years ended December 31,

		2003		2002		2001
		(in thousands)

Balance at the beginning of the year	$	475,993	$	428,150	$	352,832
Add:
Net income		130,918		134,103		150,353

Subtotal		606,911		562,253		503,185

Deduct:
Dividends declared:
Dividends to Parent		101,960		84,300		68,927
Preferred stock		1,960		1,960		5,627

Subtotal		103,920		86,260		74,554

Provision for preferred stock redemption and
issuance costs		-		-		481

Balance at the end of the year	$	502,991	$	475,993	$	428,150

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

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Boston Edison Company
Consolidated Balance Sheets

		December 31,
		(in thousands)
		2003				2002
Assets
Utility plant in service, at original cost	$	2,872,835			$	2,782,854
Less: accumulated depreciation		722,608	$	2,150,227		709,443	$		2,073,411

Construction work in progress				42,234				41,944

Net utility plant				2,192,461				2,115,355
Equity and other investments				9,656				11,592
Current assets:
Cash and cash equivalents		8,426				44,062
Restricted cash		3,616				3,616
Accounts receivable - customers
net of allowance of $15,692 and
$19,084 in 2003 and 2002, respectively		171,381				177,681
Accrued unbilled revenues		21,882				21,468
Fuel, materials and supplies, at average cost		13,310				13,291
Deferred tax asset		12,985				18,141
Other		6,359		237,959		5,575			283,834

Deferred debits:
Regulatory assets				1,107,561					1,265,062
Other				136,003					178,429

Total assets			$	3,683,640			$		3,854,272





Capitalization and Liabilities
Common equity:
Common stock, par value $1 per share,
100 shares authorized; 75 shares
issued and outstanding	$	-			$	-
Premium on common shares		278,795				278,795
Retained earnings		502,991	$	781,786		475,993	$		754,788

Cumulative non-mandatory redeemable preferred
stock of subsidiary				43,000					43,000
Long-term debt				657,560					840,194
Transition property securitization				377,150					445,890
Current liabilities:
Long-term debt		181,688				150,687
Transition property securitization		40,077				40,555
Notes payable		182,500				-
Accounts payable:
Affiliates		28,999				32,450
Other		90,014				117,600
Accrued interest		28,387				13,899
Other		63,475		615,140		46,971			402,162

Deferred credits:
Accumulated deferred income taxes and
unamortized investment tax credits				652,259					611,469
Power contracts				351,710					350,117
Regulatory liability - cost of removal				123,173					145,414
Other				81,862					261,238

Commitments and contingencies

			$	3,683,640			$		3,854,272

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

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Boston Edison
Consolidated Statements of Cash Flows

		Years ended December 31,

		2003			2002			2001
		(in thousands)
Operating activities:
Net income	$	130,918		$	134,103		$	150,353
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization		170,924			170,932			167,905
Deferred income taxes and investment tax credits		46,980			16,125			(51,242	)
Allowance for borrowed funds used during construction (AFUDC)		(1,212	)		(1,630	)		(972	)
Net changes in:
Accounts receivable and accrued unbilled revenues		5,886			94,565			(26,356	)
Fuel, materials and supplies, at average cost		(19	)		2,170			160
Accounts payable		(31,037	)		3,865			102,292
Other current assets and liabilities		35,364			(16,503	)		(194,582	)
Deferred debits and credits		(75,855	)		26,897			58,727

Net cash provided by operating activities		281,949			430,524			206,285


Investing activities:
Plant expenditures (excluding AFUDC)		(177,249	)		(239,032	)		(138,565	)
Investments		1,936			2,019			11,500

Net cash used in investing activities		(175,313	)		(237,013	)		(127,065	)


Financing activities:
Capital contribution		-			-			43,937
Long-term debt		-			500,000			-
Financing costs		-			(5,218	)		-
Redemptions:
Preferred stocks		-			-			(50,000	)
Long-term debt		(220,852	)		(130,020	)		(91,513	)
Net change in notes payable		182,500			(191,500	)		95,000
Repurchase of common stock		-			(250,000	)		-
Dividends paid		(103,920	)		(86,260	)		(75,220	)

Net cash used in financing activities		(142,272	)		(162,998	)		(77,796	)

Net (decrease) increase in cash and cash equivalents		(35,636	)		30,513			1,424
Cash and cash equivalents at the beginning of the year		44,062			13,549			12,125

Cash and cash equivalents at the end of the year	$	8,426		$	44,062		$	13,549




Supplemental disclosures of cash flow information:
Interest, net of amounts capitalized	$	87,008		$	81,158		$	91,007
Income taxes paid	$	8,782		$	46,483		$	164,194

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

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Notes to Consolidated Financial Statements

Note A. Business Organization and Summary of Significant Accounting Policies

1. Nature of Operations

Boston Edison currently supplies electricity at retail to an area of 590 square miles. The population of the area served with electricity at retail is approximately 1.6 million. Boston Edison also supplies electricity at wholesale for resale to other utilities and municipal electric departments.

2. Basis of Consolidation and Accounting

The accompanying Consolidated Financial Statements reflect the results of operations, comprehensive income, retained earnings, financial position and cash flows of Boston Edison and its subsidiaries, Harbor Electric Energy Company (HEEC) and BEC Funding LLC (BEC Funding). All significant intercompany transactions have been eliminated in consolidation. Certain reclassifications have been made to the prior year amounts to conform to the current year’s presentation.

Boston Edison follows accounting policies prescribed by the Federal Energy Regulatory Commission (FERC) and the Massachusetts Department of Telecommunications and Energy (MDTE). In addition, Boston Edison and its subsidiaries are subject to the accounting and reporting requirements of the Securities and Exchange Commission (SEC). The accompanying Consolidated Financial Statements conform to accounting principles generally accepted in the United States of America (GAAP). As a rate-regulated company, Boston Edison has been subject to the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). The application of SFAS 71 results in differences in the timing of recognition of certain expenses from that of other businesses and industries. The distribution and transmission business remains subject to rate-regulation and continues to meet the criteria for application of SFAS 71. Refer to Note C to these Consolidated Financial Statements for more information on regulatory assets.

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

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3. Revenues

4. Utility Plant

Utility plant is stated at original cost. The cost of replacements of property units are capitalized. Maintenance and repairs and replacements of minor items are expensed as incurred. The original cost of property retired, net of salvage value, is charged to accumulated depreciation. The incurred related cost of removal is charged against the regulatory liability - cost of removal.

5. Depreciation

Depreciation of utility plant is computed on a straight-line basis using composite rates based on the estimated useful lives of the various classes of property. The composite rates are subject to the approval of the MDTE and FERC. The overall composite depreciation rates for utility property were 2.86%, 2.89% and 2.87% in 2003, 2002 and 2001, respectively. The rates include a cost of removal component, which is collected from customers.

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

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

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

AFUDC represents the estimated costs to finance utility plant construction. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction of current interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the form of increased revenues collected as a result of higher depreciation expense. Average AFUDC rates in 2003, 2002 and 2001 were 1.40%, 2.89% and 4.14%, respectively, and represented only the costs of short-term debt.

8. Cash, Cash Equivalents and Restricted Cash

Cash, cash equivalents and restricted cash are comprised of liquid securities with maturities of 90 days or less when purchased. Restricted cash primarily represents the funds held in reserve for a trust on behalf of Boston Edison’s wholly owned subsidiary, BEC Funding LLC. These funds are available to pay the principal and interest on the transition property securitization certificates.

9. Equity Method of Accounting

Boston Edison uses the equity method of accounting for investments in corporate joint ventures in which it does not have a controlling interest. Under this method, it records as income or loss the proportionate share of the net earnings or losses of the joint ventures with a corresponding

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increase or decrease in the carrying value of the investment. The investment is reduced as cash dividends are received. Boston Edison participates in several corporate joint ventures in which it

has investments, principally its 11.1% equity investment in two companies that own and operate transmission facilities to import electricity from the Hydro-Quebec System in Canada, and its equity investments of 9.5% in each of two regional nuclear facilities that are currently being decommissioned.

10. Related Party Transactions

The accompanying Consolidated Balance Sheet as of December 31, 2003 includes $131.0 million in Other deferred charges that results from the Company’s role as the sponsor of the NSTAR Pension Plan and represents the amount of the additional minimum liability recognized in 2003 that was allocated to the other subsidiaries of NSTAR. Additionally, the accompanying December 31, 2003 and 2002 Consolidated Balance Sheets include net payables of $23.1 million and $21.3 million, respectively, to NSTAR Electric & Gas, for management and support services. Boston Edison’s goodwill amortization expense allocation payable to its affiliated companies, ComElectric, Cambridge Electric and NSTAR Gas was $34.5 million and $26.6 million for 2003 and 2002, respectively. These amounts were included in Other deferred credits. Also, included in the accompanying Consolidated Balance Sheet as of December 31, 2003 was a payable of approximately $2.0 million to the Parent Company NSTAR representing the Company’s share of postretirement benefits costs. These statements also include an accounts receivable of $50,700 and $200,900 as of December 31, 2003 and 2002, respectively, from NSTAR Communications, Inc., an affiliate. These balances represent the construction and construction costs management services provided by Boston Edison and its contractors.

11. Amortization of Goodwill and Costs to Achieve

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12. Other Income (deductions), net

Major components of other income, net were as follows:

		Years ended December 31,

(in thousands)		2003			2002			2001
Equity earnings	$	1,567		$	1,463		$	1,434
Income from demutualized securities		-			-			2,743
Interest income		111			926			3,433
Rental income		1,393			1,737			1,921
Settlement of claims		-			1,041			943
Miscellaneous other income, (includes
applicable income tax expense)		(697	)		(1,159	)		(2,320	)

	$	2,374		$	4,008		$	8,154

Major components of other deductions, net were as follows:

		Years ended December 31,

(in thousands)		2003			2002			2001
Charitable contributions	$	(653	)	$	(970	)	$	(22	)
Property taxes		(120	)		(129	)		(119	)
Miscellaneous other deductions, (includes
applicable income tax benefit)		(28	)		363			(83	)

		(801	)		(736	)		(224	)

Total other income, net	$	1,573		$	3,272		$	7,930

13. New Accounting Standards

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Boston Edison adopted SFAS 150 effective July 1, 2003. Boston Edison assessed the requirements of the Statement and has not identified any financial instruments to which SFAS

150 applies. In addition, Boston Edison has not entered into, nor modified, any financial instrument since May 31, 2003. As a result, the implementation of this Statement has not had an impact on Boston Edison’s financial position or results of operations.

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities”, as amended and revised in December 2003 (FIN 46R), which addresses the consolidation of variable interest entities (VIE’s) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise with the majority of the risks or rewards associated with the VIE. Application of this Interpretation is required for all potential VIE’s that are referred to as special-purpose entities for periods ending after December 15, 2003 and, for all other types of entities that are potential VIE’s that are not referred to as special purpose entities, the consolidation requirements apply for periods ending after March 15, 2004. Boston Edison has assessed the impact of FIN 46R and has determined that Boston Edison does have a VIE for which Boston Edison is the primary beneficiary requiring consolidation of the entity as of December 31, 2003. For all other types of entities, Boston Edison is still assessing the impact that FIN 46R will have on its consolidated financial position.

Boston Edison has a wholly owned special purpose subsidiary, BEC Funding LLC, established to facilitate the sale and administration of $725 million in notes to a special purpose trust created by two Massachusetts state agencies. Historically, Boston Edison has consolidated this entity. As part of Boston Edison’s assessment of FIN 46R, Boston Edison reviewed the substance of this entity to determine if it is still proper to consolidate this entity. Based on its review, Boston Edison has concluded that BEC Funding LLC is variable interest entity and should continue to be consolidated by Boston Edison.

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

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

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

Note B. Asset Retirement Obligations

For Boston Edison, cost of removal (negative net salvage) is recognized as a component of depreciation expense in accordance with approved regulatory treatment. Cost of removal was previously included in accumulated depreciation but is currently reflected as a regulatory liability in conjunction with the adoption of SFAS 143. As of December 31, 2003 and 2002, the estimated amount of the cost of removal included in regulatory liabilities was approximately $123 million and $145 million, respectively, based on the cost of removal component in current depreciation rates.

Note C. Regulatory Assets

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

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Regulatory assets consisted of the following:

	December 31,

(in thousands)		2003		2002
Generation-related regulatory assets, net	$	409,467	$	466,894
Power contracts (including Yankee units)		351,710		350,117
Retiree benefit costs		196,260		274,031
Merger costs to achieve		60,623		68,601
Income taxes, net		58,554		60,278
Redemption premiums		12,340		13,479
Purchased power costs		10,515		8,713
Other		8,092		22,949

Total regulatory assets	$	1,107,561	$	1,265,062

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

Generation-related regulatory assets, net

Plant and other regulatory assets related to the divestiture of Boston Edison’s generation business are recovered with a return through the transition charge. This recovery occurs through 2016 for Boston Edison and is subject to adjustment by the MDTE.

As of December 31, 2003, $425.4 million of these generation-related regulatory assets are collateralized with the Transition Property Securitization Certificates held by Boston Edison’s subsidiary, BEC Funding, LLC. The certificates are non-recourse to Boston Edison.

Power contracts

The unamortized balance of the estimated costs to close the Connecticut Yankee (CY) and Yankee Atomic (YA) nuclear power plants that are currently being decommissioned was $80.5 million at December 31, 2003. Boston Edison’s liability for CY decommissioning and its recovery ends in 2007 and for YA in 2010. However, should the actual costs exceed current estimates and anticipated decommissioning dates, Boston Edison could have an obligation beyond these periods that would be fully recoverable. These costs are recovered through Boston Edison’s transition charge. Refer to Note M, “Commitments and Contingencies,” for more discussion.

The remaining balance includes $271.2 million at December 31, 2003 representing the recognition of one purchased power contract as a derivative and its above-market value and future recovery through Boston Edison’s transition charge. Refer to Note K, “Derivative Instruments - Power Contracts” for further details.

Retiree benefit costs

The retiree benefit regulatory asset of $196.3 million is comprised of the additional minimum pension liability charge required under SFAS 87 ($172.9 million), $12.2 million in carrying charges, which will be recovered from customers in 2004, and pension and PBOP expenses related to 2003 that will be recovered in 2004 per a MDTE order, $7.0 million related to Boston

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Edison’s deferred PBOP costs, and $4.2 million related to Boston Edison’s deferred pension costs. These costs are being amortized over periods ranging from two to nine years.

Refer to Note F of these Consolidated Financial Statements for further discussion on the MDTE order.

Merger costs to achieve

An integral part of the merger was the MDTE - approved rate plan of the retail utility subsidiaries of NSTAR. Significant elements of the rate plan include a four-year distribution rate freeze, recovery of the acquisition premium (goodwill) over 40 years and recovery of transaction and integration costs (costs to achieve) over 10 years. Costs to achieve were the costs incurred to execute the merger including costs for a voluntary severance program, costs of financial advisors, legal costs and other transaction and systems integration costs. These costs are collected from Boston Edison’s distribution customers and exclude a return component. These costs have been adjusted since the original recovery began and any unrecovered costs will be included in the Company’s next rate case filing.

Income taxes, net

Approximately $30.9 million of this regulatory asset balance reflects deferred tax reserve deficiencies that the MDTE has allowed recovery of from ratepayers over a 17-year period. In addition, approximately $38.7 million in additional Boston Edison deferred tax reserve deficiencies have been recorded in accordance with a MDTE-approved settlement agreement. Offsetting these amounts is approximately $11.1 million of a regulatory liability associated with unamortized investment tax credits.

Redemption premiums

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

Purchased power costs

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

Other

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

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Note D. Income Taxes

Income taxes are accounted for in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS 109). SFAS 109 requires the recognition of deferred tax assets and liabilities for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 71 and SFAS 109, net regulatory assets of $58.6 million and $60.3 million and corresponding net increases in accumulated deferred income taxes were recorded as of December 31, 2003 and 2002, respectively. The regulatory assets represent the additional future revenues to be collected from customers for deferred income taxes.

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

		December 31,

(in thousands)		2003		2002
Deferred tax liabilities:
Plant-related	$	355,402	$	303,411
Transition costs		178,840		206,895
Other		139,418		121,136

		673,660		631,442


Deferred tax assets:
Investment tax credits		11,076		11,784
Other		40,471		44,536

		51,547		56,320

Net accumulated deferred income taxes		622,113		575,122
Accumulated unamortized investment tax credits		17,161		18,206

	$	639,274	$	593,328

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

Components of income tax expense were as follows:

(in thousands)		2003			2002			2001
Current income tax expense	$	42,977		$	74,362		$	144,779
Deferred income tax expense (benefit)		48,024			17,168			(49,715	)
Investment tax credit amortization		(1,044	)		(1,043	)		(1,097	)

Income taxes charged to operations		89,957			90,487			93,967

Tax expense on other income, net		1,015			1,795			3,607

Total income tax expense	$	90,972		$	92,282		$	97,574

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

	2003		2002		2001
Statutory tax rate	35.0	%	35.0	%	35.0	%
State income tax, net of federal income tax benefit	4.4		4.4		4.4
Investment tax credits	(0.5	)	(0.5	)	(0.4	)
Other	2.1		1.9		0.4

Effective tax rate	41.0	%	40.8	%	39.4	%

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Note E. Pension and Other Postretirement Benefits

1. Pension

Effective January 1, 2000, the pension plan of BEC Energy and COM/Energy were combined to form the NSTAR Pension Plan (the Plan). Boston Edison is the sponsor of the Plan, which is a defined benefit funded retirement plan that covers substantially all employees of NSTAR Electric & Gas.

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

The Company also maintained unfunded supplemental retirement plans for certain management employees of NSTAR Electric & Gas. Consistent with the transfer of all Boston Edison employees to NSTAR Electric & Gas, the liability for its supplemental retirement plan was transferred accordingly effective December 31, 2001.

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

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

		December 31,

(in thousands)		2003			2002
Change in benefit obligation:
Benefit obligation, beginning of the year	$	917,492		$	810,517
Service cost		17,615			14,871
Interest cost		56,727			57,564
Plan participants’ contributions		72			74
Plan amendments		-			671
Actuarial loss		2,627			102,598
Settlement payments		(18,741	)		(19,545	)
Benefits paid		(49,080	)		(49,258	)

Benefit obligation, end of the year	$	926,712		$	917,492




Change in Plan assets:
Fair value of Plan assets, beginning of the year	$	665,897		$	790,704
Actual gain (loss) on Plan assets, net		150,978			(105,578	)
Employer contribution		80,000			49,500
Plan participants’ contributions		72			74
Settlement payments		(18,741	)		(19,545	)
Benefits paid		(49,080	)		(49,258	)

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

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The Plan’s funded status was as follows:

		December 31,

(in thousands)		2003			2002
Funded status	$	(97,586	)	$	(251,595	)
Unrecognized actuarial net loss		394,408			515,859
Unrecognized transition obligation		379			980
Unrecognized prior service cost		(7,418	)		(8,228	)

Net amount recognized	$	289,783		$	257,016

Amounts recognized in the accompanying Consolidated Balance Sheets consisted of:

		December 31,

(in thousands)		2003			2002
Accrued retirement liability	$	(14,483	)	$	(177,675	)
Intangible asset		379			980
Regulatory asset		185,448			262,616
Amount allocated to affiliates		118,439			171,095

Net amount recognized	$	289,783		$	257,016

Weighted average assumptions were as follows:

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

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

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

		Years ended December 31,

(in thousands)		2003			2002			2001
Service cost	$	17,615		$	14,871		$	14,027
Interest cost		56,727			57,564			57,050
Expected return on Plan assets		(58,917	)		(74,426	)		(78,397	)
Amortization of prior service cost		(810	)		(863	)		(118	)
Amortization of transition obligation		601			601			601
Recognized actuarial loss		32,017			13,451			775

Net periodic benefit cost/(income) before allocation to affiliates	$	47,233		$	11,198		$	(6,062	)

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Certain postretirement health care benefits are eligible to certain active NSTAR Electric & Gas employees and certain retired non-union employees in conjunction with the NSTAR postretirement plan. Pursuant to the Internal Revenue Code, the Company funds these benefits through a 401(h) subaccount of the Pension Plan, subject to certain conditions and limitations. Assets in the trust beyond those in the 401(h) subaccount must be used to pay pension benefits and cannot be used to pay postretirement health care benefits. Assets included in the 401(h) subaccount must only be used for postretirement health care benefits.

The Company, as a sponsor of the Plan, allocated net costs and was reimbursed by its affiliated companies a total of $16.4 million and $4.3 million in 2003 and 2002, respectively.

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


	Plan Assets		Target	Permissible

	2003	2002	Percentages	Ranges

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

Total	100%	100%	100%

In March 2003, the investment goals were revised and new target percentages and permissible ranges were identified. As a result, the 2003 and 2002 asset allocation percentages may not fall within the revised permissible ranges.

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

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

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

Funded Status

The Plan’s assets were affected by significant declines in the financial markets from 2000 through 2002. These conditions have impacted the funded status of the Plan at both December 31, 2003 and 2002. As a result of the negative investment performance and, despite the positive Plan investment performance in 2003, at December 31, 2003 and 2002, the accumulated benefit obligation exceeded Plan assets. Therefore, Boston Edison is required to recognize an additional

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minimum liability as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS 87) and SFAS No. 132, “Employers’ Disclosures about Pensions and Postretirement Benefits.” The additional minimum liability results in the netting of the prepaid pension cost with the additional minimum liability on the accompanying Consolidated Balance Sheet.

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

On October 31, 2003, the MDTE approved Boston Edison’s request for a reconciliation rate adjustment mechanism related to pension and PBOP costs. As part of this ruling, Boston Edison is allowed to record a regulatory asset in lieu of taking a charge to OCI for the additional minimum liability adjustment mentioned above. As of December 31, 2003 and 2002, Boston Edison has recorded a regulatory asset of $172.9 million and $262.6 million, respectively. The regulatory asset is shown as part of Deferred debits in the accompanying Consolidated Balance Sheets.

Boston Edison anticipates contributing approximately $40 million to its Plan in 2004.

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

(in thousands)
2004	$	55,474
2005		56,951
2006		58,682
2007		61,192
2008		63,884
2009 - 2013		373,949

Total	$	670,132

2. Other Postretirement Benefits

Boston Edison provides, through the Group Welfare Benefit Plan for Retirees of NSTAR, health care and other benefits to retired employees who meet certain age and years of service eligibility requirements. These benefits included health and life insurance coverage and until April 1, 2003, reimbursement of certain Medicare premiums for certain retirees. Under certain circumstances, eligible retirees are required to make contributions for postretirement benefits.

To fund these postretirement benefits, NSTAR, on behalf of Boston Edison and other subsidiaries, makes contributions to various VEBA trusts that were established pursuant to section 501(c)(9) of the Internal Revenue Code.

The funded status of the Plan cannot be presented separately for Boston Edison since the Company participates in the Plan trusts with other subsidiaries. Plan assets are available to provide benefits for all Plan participants who are former employees of Boston Edison and other subsidiaries of NSTAR.

The net periodic postretirement benefits cost allocated to the Company was $25.8 million, $23.8 million and $14.1 million in 2003, 2002 and 2001, respectively.

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In December 2003, the FASB issued Staff Position (FSP) 106-1, “Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Act). The Act provides for drug benefits for retirees over the age of 65 under a new Medicare Part D program. For employers like NSTAR, who currently provide retiree medical programs for former employees over the age of 65, there are subsidies available which are inherent in the Act. The Act entitles these employers to a direct tax-exempt federal subsidy. However, since the effective date of the Act was December 2003 and because most employers have not had time to consider the accounting considerations and that there is no appropriate accounting guidance for the federal subsidy, the FASB issued this FSP to allow employers a one-time election to defer recognition of the impact of the Act in the employer’s accounting until formal guidance is issued. NSTAR elected to defer recognition of the provisions of this Act until further accounting guidance is issued. As a result, the provisions of the Act are not reflected in the following disclosure. The issuance of formal accounting guidance may require a change to previously reported information. NSTAR is continuing to monitor the impact of the Act.

3. Saving Plan

Boston Edison contributes proportionately into a defined contribution 401(k) plan for substantially all employees of NSTAR Electric & Gas. Matching contributions (which are equal to 50% of the employees’ deferral up to 8% of compensation) included in the accompanying Consolidated Statements of Income amounted to $5 million in both 2003 and 2002 and $4 million in 2001. The plan was amended, effective April 1, 2001, to allow participants the ability to reallocate their investments in the NSTAR Common Share Fund to other investment options. Effective January 1, 2002, consistent with EGTRRA, the plan was further amended to allow for increased maximum annual pre-tax contributions and additional “catch-up” pre-tax contributions for participants age 50 or older, acceptance of other types of “roll-over” pre-tax funds from other plans and the option of reinvesting dividends paid on the NSTAR Common Share Fund or receiving such dividends in cash. The election to reinvest dividends paid on the NSTAR Common Share fund or receive the dividends in cash is subject to a freeze period beginning seven days prior to the date any dividend is paid. During this period, participants cannot change their election. Dividends are paid to this plan four times a year on February 1, May 1, August 1 and November 1.

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

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

The PAM order authorizes Boston Edison to recover its pension and PBOP expenses through a reconciling rate mechanism. This mechanism removes the volatility in earnings that may have resulted from requirements of existing accounting standards and provides for an annual filing and rate adjustment with the MDTE. This order effectuates the Accounting Order, which allowed Boston Edison to record a regulatory asset in lieu of taking a charge to OCI at December 31, 2002 for the additional minimum liability in accordance with SFAS 87. In addition, the order revised the effective date included in the Accounting Order on which the Company could begin to defer the difference between the level of pension and PBOP expense included in rates and the amounts that are required to be recorded under the pension and PBOP accounting rules to September 1, 2003. This date coincides to the expiration of Boston Edison’s four-year distribution rate freeze. As a result, Boston Edison recognized $7.8 million of expenses in the third quarter of 2003 that had been deferred earlier in the year. In accordance with the PAM

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order, the Company recognized $9.8 million of revenue related to carrying charges on the net prepaid balance. This carrying charge will be collected from customers in 2004.

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

Note G. Capital Stock

1. Common Stock Repurchase

On October 15, 2002, Boston Edison repurchased and retired 25 shares of its Common Stock, par value $1 per share, for $250 million with a portion of the proceeds from the $500 million long-term debt that was issued in October 2002.

2. Cumulative Preferred Stock

Non-mandatory redeemable series:

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

(in thousands, except per share amounts)

Series	Current Shares Outstanding	Redemption Price/Share	December 31, 2003	December 31, 2002
4.25%	180,000	$103.625	$18,000	$18,000
4.78%	250,000	$102.80	25,000	25,000

Total non-mandatory redeemable series			$43,000	$43,000

Note H. Indebtedness

1. Long-Term Debt

Boston Edison’s long-term debt consisted of the following:

		December 31,

(in thousands)		2003			2002
Debentures:
6.80%, due March 2003	$	-		$	150,000
Floating rate (1.65% in 2003), due October 2005		100,000			100,000
7.80%, due May 2010		125,000			125,000
4.875%, due October 2012		400,000			400,000
7.80%, due March 2023		181,000			181,000
Sewage facility revenue bonds, due through 2015		18,248			19,882
Massachusetts Industrial Finance Agency (MIFA)
bonds:
5.75%, due February 2014		15,000			15,000
Transition Property Securitization Certificates:
6.45%, due September 2003		-			40,555
6.62%, due March 2005		74,727			103,390
6.91%, due September 2007		170,876			170,876
7.03%, due March 2010		171,624			171,624

		1,256,475			1,477,327
Amounts due within one year		(221,765	)		(191,243	)

Total long-term debt	$	1,034,710		$	1,286,084

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

Sewage facility revenue bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature through 2015. Scheduled redemptions of $1.65 million were made in 2003 and 2002. The weighted average interest rate of the bonds was 7.375% in 2003 and 2002. A portion of the proceeds from the bonds is in a reserve with the trustee. If HEEC should have insufficient funds to pay for extraordinary expenses, Boston Edison would be required to make additional capital contributions or loans to the subsidiary up to a maximum of $1 million.

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

The aggregate principal amounts of Boston Edison’s long-term debt (including securitization certificates and sinking fund requirements) due in the five years subsequent to 2003 are approximately $221.8 million in 2004, $170.1 million in 2005, $70.3 million in 2006, $70.2 million in 2007 and $70.1 million in 2008.

2. Financial Covenant Requirements

Boston Edison has no financial covenant requirements under its long-term debt arrangements.

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The Transition Property Securitization Certificates held by Boston Edison’s subsidiary, BEC Funding, LLC, are collaterized with a securitized regulatory asset with a balance of $425.4 million and $493.6 million as of December 31, 2003 and 2002, respectively. Boston Edison, as servicing agent for BEC Funding, collected $102.3 million in 2003. These Certificates are non-recourse to Boston Edison.

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

Interest rates on the outstanding borrowings generally are money market rates and averaged 1.20% and 1.38% in 2003 and 2002, respectively. In aggregate, short-term borrowings totaled $182.5 million and zero at December 31, 2003 and 2002, respectively.

Note I. Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of securities for which it is practicable to estimate the value:

1. Cash and Cash Equivalents

The carrying amounts of $8.4 million and $44.1 million for 2003 and 2002, respectively, approximate fair value due to the short-term nature of these securities.

2. Indebtedness (Excluding Notes Payable)

The fair values of long-term indebtedness are based upon the quoted market prices of similar issues. Carrying amounts and fair values as of December 31, 2003 and 2002 were as follows:

	2003		2002

	Carrying	Fair		Carrying	Fair
(in thousands)	Amount	Value		Amount	Value
Long-term indebtedness	$1,256,475	$1,373,110		$1,477,326	$1,480,510
(including current maturities)

Note J. Contracts for the Purchase of Energy

Boston Edison expects to continue to make periodic market solicitations for default service and standard offer power supply consistent with provisions of the Massachusetts Electric Restructuring Act of 1997 (Restructuring Act) and MDTE orders. Boston Edison has existing

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

Capacity costs of long-term contracts reflect Boston Edison’s proportionate share of capital and fixed operating costs of certain generating units. In 2003, these costs were attributed to 329 MW of capacity purchased. Energy costs are paid to generators based on a price per kilowatt-hour actually received into Boston Edison’s distribution system and are included in the total cost. Total capacity purchased in 2003 was 809.3 MW.

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

					Boston Edison’s Proportionate share (in thousands)
	Range of							Capacity Charge
	Contract	Units of			2003		2003	Obligation
Fuel Type of	Expiration	Capacity			Capacity		Total	Through Contract
Generating Unit	Dates	Purchased			Cost		Cost	Expiration Date
		%Range	Total MW
Natural Gas	2010-2015	23.5-46.5	480.0	$	69,310	$	250,256	$	732,515
Nuclear	2004	38.2	261.3		-		84,110		-
Oil	2005-2019	100	68.0		3,777		4,527		39,328

Total			809.3	$	73,087	$	338,893	$	771,843

Boston Edison’s total capacity and/or energy costs associated with these contracts in 2003, 2002 and 2001 were approximately $339 million, $407 million and $415 million, respectively. Boston Edison’s capacity charge obligation under these contracts for the years after 2003 is as follows:

		Capacity Charge
(in thousands)		Obligation
2004	$	73,155
2005		79,185
2006		77,376
2007		80,508
2008		82,999
Years thereafter		378,620

	$	771,843

Boston Edison has entered into a short-term power purchase agreement to meet its entire default service supply obligation, other than to large customers, for the period January 1, 2004 through June 30, 2004 and for 50% of its obligation, other than to large customers, for the second-half of 2004. Boston Edison has entered into a short-term power purchase agreement to meet its entire default service supply obligation for large customers through March 2004. A Request for Proposals will be issued quarterly in 2004 for the remainder of the obligation for large customers and semi-annually for the non-large customers in accordance with MDTE regulations. Boston

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Edison entered into agreements ranging in length from six to twelve-months effective January 1, 2003 through December 31, 2003 with suppliers to provide full default service energy and ancillary service requirements at contract rates approved by the MDTE.

Note K. Derivative Instruments - Power Contracts

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

Boston Edison has one purchased power contract that contains components with pricing mechanisms that are based on a pricing index, such as the Gross National Product or Consumer Price Index. Although these factors are only applied to certain ancillary pricing components of this agreement, as required by the interpretation of DIG Issue C15, Boston Edison began recording this contract at fair value on its Consolidated Balance Sheets during 2002. As a result, the recognition of a liability for the fair value of the above-market portion of this contract at December 31, 2003 is approximately $271.2 million and is a component of Deferred credits - Power contracts on the accompanying Consolidated Balance Sheets. Boston Edison has recorded a corresponding regulatory asset to reflect the future recovery of the above-market component of this contract through its transition charge. Therefore, as a result of this regulatory treatment, the recording of this contract on its accompanying Consolidated Balance Sheets does not result in an earnings impact.

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

Note L. Other Electric Utility Matters

Service Quality Indicators

On February 28, 2003, NSTAR Electric, including Boston Edison, filed their 2002 Service Quality Reports with the MDTE that reflected significant improvements in reliability and performance; the reports indicate that no penalty was assessed for 2002. The MDTE concurred with Boston Edison’s determination in an order issued on September 30, 2003. Boston Edison monitors its

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service quality continuously to determine its contingent liability, and if it were determined that a liability has been incurred and is estimable, an appropriate liability would be accrued. Annually, Boston Edison makes a service quality performance filing with the MDTE. Any settlement or rate order that would result in a different liability level from what has been accrued would be adjusted in the period an agreement is reached with the MDTE.

As of December 31, 2003, Boston Edison’s performance has met or exceeded the applicable established benchmarks such that no liability has been accrued for 2003.

Note M. Commitments and Contingencies

1. Contractual Commitments

Boston Edison also has leases for facilities and equipment. The estimated minimum rental commitments under non-cancellable operating leases for the years after 2003 are as follows:


(in thousands)
2004	$	11,729
2005		10,572
2006		7,541
2007		6,231
2008		5,331
Years thereafter		26,519

	$	67,923

The total expense for both lease rentals and transmission agreements was $58.6 million in 2003, 58.1 million in 2002 and $57.1 million in 2001, net of capitalized expenses of $1.6 million in 2003, $1.9 million in 2002 and $2.3 million in 2001.

Boston Edison has entered into a short-term purchase agreement to meet its entire default service supply obligation, other than to large customers, for the period January 1, 2004 through June 30, 2004 and for 50% of its obligation, other than to large customers, for the second-half of 2004. Boston Edison has entered into a short-term power purchase agreement to meet its entire default service supply obligation for large customers through March 2004. A Request for Proposals will be issued quarterly in 2004 for the remainder of the obligation for large customers and semi-annually for non-large customers in accordance with MDTE regulations. Boston Edison entered into agreements ranging in length from six to twelve-months effective January 1, 2003 through December 31, 2003 with suppliers to provide full default service energy and ancillary service requirements at contract rates approved by the MDTE. Boston Edison is recovering payments it is making to suppliers from its customers and has financial and performance assurances and financial guarantees in place with those suppliers to protect Boston Edison from risk in the unlikely event any of its suppliers encounter financial difficulties or fail to maintain an investment grade credit rating. In connection with certain of these agreements, should, in the unlikely event, Boston Edison receive a credit rating below investment grade, it potentially could be required to obtain certain financial commitments, including but not limited to, letters of credit. Refer to Note J, “Contracts for the Purchase of Energy” for a further discussion.

2. Electric Equity Investments and Joint Ownership Interest

Boston Edison has an equity investment of approximately 11.1% in two companies that own and operate transmission facilities to import electricity from the Hydro-Quebec system in Canada. As an equity participant, Boston Edison is required to guarantee, in addition to its own share, the obligations of those participants who do not meet certain credit criteria. At December 31, 2003,

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Boston Edison’s portion of these guarantees amounted to $8.4 million. New England Hydro-Transmission Electric Company, Inc. (NEH) and New England Hydro-Transmission Corporation (NHH) have agreed to use their best efforts to limit their equity investment to 40% of their total capital during the time NEH and NHH have outstanding debt in their capital structure. In order to meet their best efforts obligations pursuant to the Equity Funding Agreement dated June 1, 1985, as amended, for NEH and NHH, in 2003, NEH repurchased a total of 270,000 of its outstanding shares from all equity holders and NHH repurchased a total of 1,075 outstanding shares from all equity holders. Through December 31, 2003, Boston Edison’s reduction of its equity ownership resulting from NEH buy-back of 29,837 shares and NHH buy-back of 119 shares was approximately $650,000.

Boston Edison has an equity ownership of 9.5% in both Connecticut Yankee Atomic Power Company (CYAPC) and Yankee Atomic Electric Company (YAEC) (collectively, the Yankee Companies). Periodically, Boston Edison obtains estimates from the management of the Yankee Companies on the cost of decommissioning the Connecticut Yankee nuclear unit (CY) and the Yankee Atomic nuclear unit (YA). These nuclear units are completely shut down and are currently conducting decommissioning activities.

Based on estimates from the Yankee Companies’ management as of December 31, 2003, the total remaining cost for decommissioning each nuclear unit is approximately as follows: $666.4 million for CY and $181.3 million for YA. Of these amounts, Boston Edison is obligated to pay $63.3 million towards the decommissioning of CY and $17.2 million toward YA. These estimates are recorded in the accompanying Consolidated Balance Sheets as Power contract liabilities with a corresponding regulatory asset and do not impact the current result of operations. These estimates may be revised from time to time based on information available to the Yankee Companies regarding future costs.

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

3. Environmental Matters

As of December 31, 2003, Boston Edison is involved in 4 state regulated properties (“Massachusetts Contingency Plan, or “MCP” sites”) where oil or other hazardous materials were previously spilled or released. Boston Edison is required to clean up or otherwise remediate these properties in accordance with specific state regulations. There are sometimes uncertainties associated with total remediation costs due to the final selection of the specific cleanup technology and the particular characteristics of the different sites. Estimates of approximately $0.2 million and $0.4 million are included as liabilities in the accompanying Condensed Consolidated Balance Sheets at December 31, 2003 and 2002, respectively.

In addition to the MCP sites, Boston Edison also face possible liability as a result of involvement in 8 multi-party disposal sites or third party claims associated with contamination remediation.

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Boston Edison generally expects to have only a small percentage of the total potential liability for these sites. Estimates of approximately $3.4 million and $3.3 million are included as liabilities in the accompanying Consolidated Balance Sheets at December 31, 2003 and 2002, respectively.

4. Regulatory and Legal Proceedings

a. Regulatory proceedings

In December 2003, Boston Edison 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 Boston Edison effective January 1, 2004. The filings were updated in February 2004 to reflect final 2003 costs and revenues, which are subject to final reconciliation.

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

Effective September 1, 2003, Boston Edison’s Standard Offer Service Fuel Adjustment (SOSFA) rates were modified upon approval by the MDTE. The MDTE has allowed companies to adjust prices to reduce deferred cost balances that arise due to rapidly changing market costs for the oil and natural gas used to generate electricity and the SOSFA is designed to collect the costs of fuel that companies incur for purchasing electricity from their suppliers to serve their standard offer service customers. The Boston Edison SOSFA was reduced to zero per kilowatt-hour. This change followed an increase in this rate adjustment from zero to 0.902 cents per kilowatt-hour that was effective May 1, 2003. The SOSFA was at zero from April 1, 2002 through April 30, 2003. The MDTE has ruled that these fuel index adjustments are excluded from the 15% rate reduction requirement under the Restructuring Act.

Effective January 1, 2004, NSTAR Electric’s SOSFA rates was modified again with the approval of the MDTE. The Boston Edison SOSFA remained at zero per kilowatt-hour.

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b. Other Legal Matters

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

5. Financial and Performance Guarantees

On a limited basis, Boston Edison may enter into agreements providing financial assurance to third parties. Such agreements include surety bonds and other guarantees.

At December 31, 2003, outstanding guarantees totaled $15.1 million as follows:

(in thousands)
Surety Bonds	$	6,720
Other Guarantees		8,400

Total Guarantees	$	15,120

As of December 31, 2003, Boston Edison has purchased a total of approximately $0.3 million of performance surety bonds for the purpose of obtaining licenses, permits and rights-of-way in various municipalities. In addition, Boston Edison has purchased $6.4 million in worker’s compensation self-insurer bonds. These bonds support the guarantee by Boston Edison to the Commonwealth of Massachusetts required as part of Boston Edison’s workers’ compensation self-insurance program.

Boston Edison has also issued $8.4 million of residual value guarantees related to its equity interest in the Hydro-Quebec transmission companies.

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

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

No event that would be described in response to this Item 9 has occurred with respect to Boston Edison Company.

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Item 9A. Controls and Procedures

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

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

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

Part IV

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

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

1.	Financial Statements:
		Page

Report of Independent Auditors		27

Consolidated Statements of Income for the years ended December 31,
2003, 2002 and 2001		28

Consolidated Statements of Comprehensive Income for the years ended
December 31, 2003, 2002 and 2001		29

Consolidated Statements of Retained Earnings for the years ended
December 31, 2003, 2002 and 2001		29

Consolidated Balance sheets as of December 31, 2003 and 2002		30

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

Notes to Consolidated Financial Statements		32


2.	Financial Statement Schedules:

Schedule II - Valuation and Qualifying Accounts for the years ended
December 31, 2003, 2002 and 2001		59

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3.		Exhibits:

Refer to the exhibits listing beginning below.

(b)		Reports on Form 8-K:

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

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

Incorporated by reference unless designated otherwise:

		Exhibit	SEC Docket
Exhibit 3	Articles of Incorporation and By-Laws
3.1	Restated Articles of Organization.	3.1	1-2301 Form 10-Q for the quarter ended June 30, 1994.
3.2	Boston Edison Company Bylaws dated April 19, 1977, as amended January 22, 1987, January 28, 1988, May 24, 1988 and November 22, 1989.	3.1	1-2301 Form 10-Q for the quarter ended June 30, 1990.
Exhibit 4	Instruments Defining the Rights of Security Holders, Including Indentures
4.1	Indenture dated September 1, 1988, between Boston Edison Company and The Bank of New York (as successor to Bank of Montreal Trust Company).	4.1	1-2301 Form 10-Q for the quarter ended September 30, 1988.
4.2	Votes of the Pricing Committee of the Board of Directors of Boston Edison Company taken May 18, 1995 re 7.80% debentures due May 15, 2010.	4.1.5	1-2301 Form 10-K for the year ended December 31, 1995.

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4.3	Votes of the Board of Directors of Boston Edison Company taken October 8, 2002 re $500 million aggregate principal amount of unsecured debentures ($400 million, 4.875% due in 2012 and $100 million, floating rate due in 2005).	4.2	1-2301 Form 8-K dated October 11, 2002.
Management agrees to furnish to the Securities and Exchange Commission, upon request, a copy of any other agreements or instruments of Boston Edison and its subsidiaries defining the rights of holders of any long-term debt whose authorization does not exceed 10% of total assets.
Exhibit 10	Material Contracts
10.1	Boston Edison Company Restructuring Settlement Agreement dated July 1997.	10.12	1-2301 Form 10-K for the year ended December 31, 1997.
10.2	Boston Edison Company and Sithe Energies, Inc. Purchase and Sale and Transition Agreements dated December 10, 1997.	10.1	1-2301 Form 10-Q for the quarter ended March 31, 1998.
10.3	Boston Edison Company and Entergy Nuclear Generation Company Purchase and Sale Agreement dated November 18, 1998.	10.12	1-2301 Form 10-K for the year ended December 31, 1999.

Exhibit 12	Statement re Computation of Ratios
12.1	Computation of Ratio of Earnings to Fixed Charges for the Year ended December 31, 2003 (filed herewith).
12.2	Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements for the Year ended December 31, 2003 (filed herewith).
Exhibit 21	Subsidiaries of the Registrant
21.1	Incorporated herein by reference (Boston Edison Form 10-K for the year ended December 31, 2002, File No. 1-2301).

Exhibit 23	Consent of Independent Accountants
23.1	(filed herewith)

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SCHEDULE II

BOSTON EDISON COMPANY

VALUATION AND QUALIFYING ACCOUNTS

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

(Dollars in Thousands)

				Additions				Deductions
		Balance at		Provisions						Balance
		Beginning		Charged to				Accounts		At End
Description		of Year		Operations		Recoveries		Written Off		of Year
Allowance for Doubtful Accounts
Year Ended December 31, 2003	$	19,084	$	6,225	$	2,964	$	12,584	$	15,692
Year Ended December 31, 2002	$	24,691	$	10,699	$	4,630	$	20,936	$	19,084
Year Ended December 31, 2001	$	22,415	$	13,000	$	2,089	$	12,813	$	24,691

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FORM 10-K

BOSTON EDISON COMPANY

DECEMBER 31, 2003

SIGNATURES

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

		Boston Edison Company

		(Registrant)

Date: March 1, 2004	By:	/s/ ROBERT J. WEAFER, JR.

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

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated as of the 1^st day of March 2004.

Signature		Title

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

Thomas J. May		Officer and Director

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

James J. Judge		Chief Financial Officer and Director

/s/ DOUGLAS S. HORAN		Senior Vice President/Strategy, Law and

Douglas S. Horan		Policy, Clerk, General Counsel and Director

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


Massachusetts		04-1278810

(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification Number)
800 Boylston Street, Boston, Massachusetts		02199

(Address of principal executive offices)		(Zip code)

Class	Outstanding at March 1, 2004
Common Stock, $1 par value	75 shares

The Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K as a wholly-owned subsidiary and is therefore filing this Form 10-K with the reduced disclosure format.
Documents Incorporated by Reference
None

Commission file number	1-2301