Boston Edison Company Form 10-K

Boston Edison Company

Form 10-K Annual Report - December 31, 2005

	Part I	Page

Item 1.	Business	2
Item 1A	Risk Factors	8
Item 1B	Unresolved Staff Comments	9
Item 2.	Properties	9
Item 3.	Legal Proceedings	10

	Part II

Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	10
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	10
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	29
Item 8.	Financial Statements and Supplementary Data	31
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	58
Item 9A.	Controls and Procedures	58
Item 9B.	Other Information	58
	Part IV

Item 15.	Exhibits and Financial Statement Schedules	58


Signatures		64



	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. As a wholly-owned subsidiary of NSTAR, 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 Boston Edison’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.

Table of Contents

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. Boston Edison serves approximately 700,000 electric distribution customers in the City of Boston and 39 surrounding communities. NSTAR is a holding company engaged through its subsidiaries in the energy delivery business serving approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric distribution customers in 81 communities and approximately 300,000 natural gas distribution customers in 51 communities. NSTAR’s retail distribution 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 distribution companies collectively operate as “NSTAR Electric.” Reference in this report to “NSTAR” shall mean NSTAR or NSTAR and its subsidiaries as the context requires. Reference in this report to “NSTAR Electric” shall mean each of Boston Edison, ComElectric and Cambridge Electric together. 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 first wholly-owned 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. Boston Edison's second wholly-owned special-purpose subsidiary, BEC Funding II, LLC (BEC Funding II) was established to facilitate the sale, on March 1, 2005, of $265.5 million of electric rate reduction certificates at a public offering. The certificates of both special-purpose subsidiaries 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. BEC Funding and BEC Funding II are included in the consolidated financial statements of Boston Edison.

(b) Financial Information about Industry Segments

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

(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. Boston Edison also supplies electricity at wholesale for resale to municipal electric departments. Electric operating revenues and energy sales percentages by customer class for the last three years consisted of the following:

	Revenues $			Energy Sales (MWH)
Retail:	2005	2004	2003	2005	2004	2003
Commercial	56%	57%	57%	62%	61%	61%
Residential	36%	35%	34%	28%	28%	28%
Industrial	6%	6%	7%	8%	8%	8%
Other	1%	1%	1%	1%	1%	1%
Wholesale and contract sales	1%	1%	1%	1%	2%	2%

Electric Rates

Retail electric delivery rates are established by the MDTE and are comprised of:

-		distribution charges, which include a fixed customer charge, energy and demand charges (to collect the costs of building and expanding the infrastructure to deliver power to its destination, as well as ongoing operating and maintenance costs), and a reconciling rate adjustment mechanism for recovery of costs associated with Boston Edison's obligation to provide its attributable share of NSTAR Electric & Gas employees qualified pension and other postretirement benefits,
-		a transition charge (to collect costs primarily for previously held investments in generating plants and costs related to above market power contracts),
-		a transmission charge (to collect the cost of moving the electricity over high voltage lines from generating plants to substations located within Boston Edison’s service area),
-		an energy conservation charge (legislatively-mandated charge to collect costs for demand-side management programs) and
-		a renewable energy charge (legislatively-mandated charge to collect the cost to support the development and promotion of renewable energy projects).

Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers for those who choose not to buy energy from a competitive energy supplier. Standard offer service option for customers ended on February 28, 2005. Therefore, all customers who had not chosen to receive service from a competitive supplier were provided default service, which was designated basic service thereafter. Basic service rates are reset every six months (every three months for large commercial and industrial customers). The price of basic service is intended to reflect the average competitive market price for power. As of December 31, 2005, 2004 and 2003, customers of Boston Edison had approximately 26%, 25% and 27%, respectively, of their load requirements provided by competitive energy suppliers.

On December 30, 2005, the MDTE approved a rate Settlement Agreement between the Attorney General of Massachusetts, NSTAR and several interveners. The Settlement Agreement contains, among other items, a reduction to Boston Edison's transition rates of approximately $15 million of the total $20 million NSTAR Electric decrease from what would otherwise have been billed in 2006. Subsequent to this initial reduction, any change in distribution rates will be offset by an equal and opposite change in the transition rates through 2012. This Settlement Agreement also permits Boston Edison to increase its distribution rates by approximately $23 million of the total $30 million that NSTAR Electric will increase effective May 1, 2006. Refer to the "Rate Settlement Agreement" section of Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for more details.

Sources and Availability of Electric Power Supply

For basic service power supply, Boston Edison makes periodic market solicitations consistent with MDTE regulations. During 2005, Boston Edison entered into short-term power purchase agreements to meet its entire basic service supply obligation, other than to its largest customers, for the period January 1, 2006 through June 30, 2006 and for 50% of its obligation, other than to these large customers, for the second half of 2006. Boston Edison has entered into short-term power purchase agreements to meet its entire basic service supply obligation for large customers through June 2006. A request for proposals will be issued quarterly in 2006 for the remainder of the obligation for large customers and semi-annually for non-large customers. For 2005, Boston Edison entered into agreements ranging in length from three to twelve months.

Boston Edison fully recovers its payments to suppliers through MDTE-approved rates billed to customers. During late 2004 and early 2005, Boston Edison completed several transactions to buy-out or restructure certain of its long-term power purchase contracts. Refer to the accompanying Consolidated Financial Statements, Note L, for more detail.

The December 30, 2005 Settlement Agreement approved by the MDTE requires Boston Edison to design a policy for the procurement of basic service supply for residential customers to take effect July 1, 2006, permitting Boston Edison to execute energy supply contacts for one, two and three-years procuring fifty, twenty-five and twenty-five percent, respectively, of its total energy load requirements. Boston Edison will work with the Attorney General of Massachusetts and a low-income support organization to develop a staggered schedule to implement this provision, including a method for further review and modification to potentially include longer-term contracts that are anticipated to reduce price volatility for small consumers.

Boston Edison's load for 2005 reached an all-time peak demand of 3,441 megawatts (MW) on July 27, which was 4% higher than the previous all-time peak demand level of 3,311 MW established in 2001.

Locational Installed Capacity (LICAP)

On March 23, 2005, the Federal Energy Regulatory Commission (FERC) unanimously approved an Independent System Operator-New England (ISO-New England) plan to implement LICAP, a new market rule designed to compensate wholesale generators for their capacity with an implementation date of January 1, 2006. FERC subsequently revised this date to no earlier than October 2006. The new LICAP rules require electric load serving entities (LSE), like Boston Edison, to utilize capacity within the zones where load is served. The current market structure allows capacity located anywhere in New England to count towards an LSE's obligation, regardless of load zone. Boston Edison's service territory covers two of the five capacity zones in New England: Northeastern Massachusetts (NEMA) and Rest of Pool (ROP). NEMA is import-constrained and could potentially see higher capacity prices than the ROP. The majority of Boston Edison's customers are in the NEMA load zone. At this point, it is likely that the completion of Boston Edison's 345kV transmission project will reduce transmission constraints causing capacity prices between NEMA and ROP to converge. This could ultimately render this locational aspect of LICAP a minimal factor for Boston Edison's customers. However, since the new market rules require that a certain amount of capacity be utilized in the NEMA zone, these requirements could impact pricing for capacity in the NEMA zone.

Additionally, several generators in the NEMA zone have filed with the FERC for cost of service-type agreements called Reliability Must Run agreements for the recovery of their costs prior to the implementation of LICAP. The new LICAP rules are likely to increase overall capacity pricing levels in New England. Since the New England market, as a whole, is currently in a surplus position, capacity trades at a relatively low price. One of the goals of LICAP is to provide a higher level of compensation to generators than what is currently being earned in this surplus market. Boston Edison is opposed to LICAP as it will likely increase the price of power to NSTAR Electric's customers without any assurance that new capacity will be built. As a result, NSTAR (and other parties) have appealed the FERC's LICAP decision in federal court. Additionally, while LICAP has been approved by FERC, the specific parameters of the capacity pricing mechanism are still being contested at FERC. A final decision on these matters is expected sometime in 2006. On October 21, 2005, FERC issued an Interim Order Regarding Settlement Procedures and Directing Compliance Filing. In this Order, the FERC gives the parties in this proceeding a further opportunity to pursue settlement on an alternative to the LICAP mechanism. FERC further directed that a settlement judge be appointed to manage the process. On January 31, 2006, this Settlement Judge, along with other parties, requested from the FERC an extension to file the Settlement Agreement and accompanying documents within 34 days. On March 6, 2006, a Settlement Agreement was filed with FERC and will remain open until reply comments are filed on April 12, 2006 by the parties. Boston Edison cannot predict the actual impact these changes will have on Boston Edison and its customers, but expects all costs incurred to be fully recoverable. In addition, the Company's December 30, 2005 rate Settlement Agreement provides an incentive mechanism for the recovery of litigation costs associated with Boston Edison's efforts to reduce wholesale energy and capacity costs and sharing of customer benefits realized from those efforts with the potential for the Company to retain 25% of any resulting savings.

Regional Transmission Organization (RTO)

On March 24, 2004, the FERC decided to schedule hearings for a joint return on equity (ROE) filing made by participating New England Transmission Owners, including Boston Edison. Refer to the accompanying "Management's Discussion and Analysis" for more detail on proceedings before the FERC.

Effective February 1, 2005, the Independent System Operator - New England (ISO-NE) became an independent entity, without a financial interest in the region's marketplace, having operating authority over the New England transmission grid and the responsibility to make impartial decisions on the development and implementation of market rules. The ISO-NE operates under a series of contractual arrangements that define its functions and responsibilities, including a Transmission Operating Agreement, which governs the relationship between the owners of transmission facilities, such as Boston Edison and the ISO-NE, as the operator of the New England transmission grid. Separate agreements govern the operation of the spot power and related markets, the ISO-NE's interactions with market participants and merchant transmission facilities.

Franchises

Through its charter, which is unlimited in time, Boston Edison has the right to engage in the business of delivering and selling electricity, and 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 who, in granting these locations, act as agents for the state. In some cases, the actions of these authorities are subject to appeal to the MDTE. The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature. Under Massachusetts law, no other entity may provide electric delivery service to retail customers within Boston Edison’s territory without the written consent of Boston Edison. This consent must be filed with the MDTE and the municipality so affected.

Regulation

Boston Edison and its wholly-owned subsidiaries: HEEC; BEC Funding, LLC; and BEC Funding II, LLC, 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.

Plant Expenditures and Financings

The most recent estimates of plant expenditures and long-term debt maturities for the years 2006 and 2007-2010 are as follows:

	2006	2007-2010
(in thousands)
Plant expenditures	$278,000	$739,000
Long-term debt	$63,380	$503,737

Plant expenditures include costs related to Boston Edison’s 345kV transmission project that in the aggregate is expected to total approximately $220 million. This project includes construction of a switching station in Stoughton, Massachusetts and a 345kV transmission line that will connect this switching station to South Boston, as well as the expansion of existing substations. A significant portion of these costs ($120 million) was incurred in 2005 ($11 million was spent in 2004), with the remaining balance to be expended in 2006. To date, this project is approximately 60% complete. This transmission line is expected to ensure continued reliability of electric service and improve power import capability in the Northeast Massachusetts area. For 2006, construction expenditures are estimated at $89 million and this project is expected to be placed in service during the summer of 2006.

As part of Boston Edison's Settlement Agreement approved by the MDTE on December 30, 2005, Boston Edison has provided the MDTE with a list of potential capital projects that that are designed to improve reliability and safety. The list is limited to capital additions and incremental operations and maintenance expenses related to programs for stray-voltage inspection survey and remediation, double pole inspection, replacement/restoration and transfer and manhole inspection, repair and upgrade. NSTAR Electric has agreed to spend at least $10 million in 2006 on these programs.

Plant expenditures in 2005 were approximately $260 million and consisted primarily of additions to Boston Edison’s distribution and transmission systems, including the 345kV project. 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.

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.”

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

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 business combinations. NSTAR operates in this marketplace by combining the resources of its utility subsidiaries activities, including Boston Edison, 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 and other environmental considerations. Boston Edison faces possible liabilities as a result of involvement in several multi-party disposal sites, state-regulated 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 the majority of these sites. Noncompliance with certain standards can, in some cases, also result in the imposition of monetary civil penalties. Refer to the “Contingencies - Environmental Matters” section in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and to the Consolidated Financial Statements, Note M, for more information.

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

Employees

Boston Edison does not have any direct employees. All labor services are provided by employees of NSTAR Electric & Gas Corporation. As of December 31, 2005, NSTAR had approximately 3,050 employees, including approximately 2,150, or 70%, who are represented by units covered by separate collective bargaining contracts.

NSTAR's labor contract with Local 369 of the Utility Workers Union of America, AFL-CIO, expired on May 15, 2005. After a brief strike, on May 29, 2005, NSTAR management and union officials agreed upon a new four-year contract expiring June 1, 2009. The union members, which represent approximately 1,850 employees, ratified the contract on May 31, 2005. Approximately 250 employees, represented by Local 12004, United Steelworkers of America, AFL-CIO, have a contract that expires on March 31, 2006. Management and Union officials are currently negotiating a new contract. Management cannot predict the outcome of this negotiation.

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 one wholesale customer through 2005) in the Boston area. Boston Edison does not have any foreign operations or export sales.

Item 1A. Risk Factors

In addition to the other information in this Annual Report on Form 10-K, investors or prospective investors should carefully consider the following risk factors.

Our electric operations are highly regulated, and any adverse regulatory changes could have a significant impact on the Company’s results of operations and its financial position.

Boston Edison’s electric operations, including the rates charged, are regulated by the FERC and the MDTE. In addition, Boston Edison’s accounting policies are prescribed by accounting principles generally accepted in the United States of America (GAAP), the FERC and the MDTE. Adverse regulatory changes could have a significant impact on results of operations and financial condition.

Potential competitive changes may adversely affect our regulated electricity business.

Under Massachusetts law, no other entity may provide electric delivery service to retail customers within Boston Edison’s service territory without the written consent of Boston Edison. Although not a trend, Boston Edison could be exposed to municipalization risk, whereby a municipality could acquire the electric delivery assets located in that city or town and take over the customer delivery service, thereby reducing Boston Edison’s revenues. Any such action would require numerous legal and regulatory consents and approvals. In addition, Boston Edison expects that any municipalization would require that Boston Edison be compensated for its assets assumed.

Changes in environmental laws and regulations affecting our business could increase our costs or curtail our activities.

Boston Edison is subject to a number of environmental laws and regulations that are currently in effect, including those related to the handling, disposal, and treatment of hazardous materials. Changes in compliance requirements or the interpretation by governmental authorities of existing requirements may impose additional costs on us, all of which could have an adverse impact on Boston Edison’s results of operations.

The Company may be required to conduct environmental remediation activities for power generating sites and other potentially unidentified sites.

Boston Edison is subject to actual or potential claims and lawsuits involving environmental remediation activities for power generating sites previously owned and other potentially unidentified sites. Boston Edison divested itself of all its generating assets over the past 10 years under terms which generally require the buyer to assume all responsibility for past and present environmental harm. Based on Boston Edison’s current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, Boston Edison does not believe that its known environmental remediation responsibilities will have a material adverse effect on Boston Edison’s results of operations, cash flows or financial position. However, discovery of currently unknown conditions at existing sites, identification of additional contaminated sites or changes in environmental regulation, could have a material adverse impact on Boston Edison’s results of operations, cash flows or financial position.

Boston Edison is subject to operational risk that could cause us to incur substantial costs and liabilities.

Our business, which involves the transmission and distribution of electricity that is used as an energy source by our customers, is subject to various operational risks, including incidents that expose the Company to potential claims for property damages or personal injuries beyond the scope of Boston Edison’s insurance coverage, and equipment failures that could result in performance below assumed levels. For example, operational performance below established target benchmark levels could cause Boston Edison to incur penalties imposed by the MDTE, up to a maximum of two percent of transmission and distribution revenues, under applicable Service Quality Indicators.

Increases in interest rates due to financial market conditions or changes in our credit ratings, could have an adverse impact on our access to capital markets at favorable rates, or at all, and could otherwise increase our costs of doing business.

Boston Edison frequently accesses the capital markets to finance its working capital requirements, capital expenditures and to meet its long-term debt maturity obligations. Increased interest rates, or adverse changes in our credit ratings, would increase our cost of borrowing and other costs that could have an adverse impact on our results of operations and cash flow. In addition, an adverse change in our credit ratings could, in addition to increasing our borrowing costs, trigger requirements that we obtain additional security for performance, such as a letter of credit, related to our energy procurement agreements. See Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” for a further discussion.

Our business is sensitive to variations in weather and have seasonal variations. In addition, severe-storm related disasters could adversely affect the Company.

Sales of electricity to residential and commercial customers are influenced by temperature fluctuations. Significant fluctuations in heating or cooling degree days could have a material impact on unit sales for any given period. In addition, extremely severe storms, such as hurricanes and ice storms, could cause damage to our facilities which may require additional costs to repair and have a material adverse impact on the Company’s results of operations, cash flows or financial position. To the extent possible, Boston Edison would seek recovery of these costs through the regulatory process.

Economic downturn, and increased costs of energy supply, could adversely affect energy consumption and could adversely affect our results of operation.

Energy consumption is significantly impacted by the general level of economic activity and cost of energy supply. Economic downturns or periods of high energy supply costs typically lead to reductions in energy consumption and increased conservation measures. These conditions could adversely impact the level of energy sales and result in less demand for energy delivery. A recession or a prolonged lag of a subsequent recovery could have an adverse effect on Boston Edison’s results of operations, cash flows or financial position.

Item 1B. Unresolved Staff Comments

None

Item 2. Properties

Boston Edison's 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, 2005, the primary and secondary overhead and underground distribution system covers approximately 10,900 and 6,600 circuit miles, respectively. In addition, Boston Edison’s transmission system consists of 119 substation facilities and approximately 733,600 active customer meters. HEEC, Boston Edison’s regulated subsidiary, has a distribution system that consists principally of a 4.1 mile 115kV 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 that location.

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

PART II

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

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, 2005.

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

Overview

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. Boston Edison serves approximately 700,000 electric distribution customers in the City of Boston and 39 surrounding communities. NSTAR is a holding company engaged through its subsidiaries in the energy delivery business serving approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric distribution customers in 81 communities and approximately 300,000 natural gas distribution customers in 51 communities. NSTAR’s retail distribution 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 distribution companies collectively operate as “NSTAR 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 Resource Authority’s wastewater treatment facility located on Deer Island in Boston, Massachusetts. Boston Edison’s first 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. Boston Edison’s second wholly-owned consolidated special-purpose subsidiary, BEC Funding II, LLC (BEC Funding II), was established to facilitate the sale, on March 1, 2005, of $265.5 million of electric rate reduction certificates at a public offering. The certificates of both special-purpose subsidiaries 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 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 and corresponding revenues but will not affect the Company’s earnings.

Rate Settlement Agreement

On December 30, 2005, the Massachusetts Department of Telecommunications and Energy (MDTE) approved a seven-year rate Settlement Agreement between the Attorney General of Massachusetts, NSTAR and several interveners. The Settlement Agreement requires Boston Edison to lower its transition rates by approximately $15 million of the total $20 million NSTAR Electric decrease from what would otherwise have been billed in 2006, and then any change in distribution rates will be offset by an equal and opposite change in transition rates, through 2012.

Major components of the agreement include:

-	A reduction in annual transition rates of approximately $15 million of the total $20 million that NSTAR Electric decreased effective January 1, 2006 and on May 1, 2006, a distribution rate increase of approximately $23 million of the total $30 million that NSTAR Electric will increase with a corresponding reduction in transition charges. Uncollected transition charges as a result of the reductions in transition rates will be deferred and collected through future rates with carrying charges at a rate of 10.88%.
-	The implementation of performance-based distribution rates (PBR) beginning January 1, 2007. The PBR will result in annual inflation-adjusted distribution rate increases that will be offset by a decrease in transition charge prices through 2012.
	-	A 50% / 50% earnings sharing mechanism based on NSTAR Electric’s aggregate return on equity should it exceed 12.5% or fall below 8.5%.
	-	Boston Edison will be permitted to collect certain safety and reliability costs through distribution rates beginning in 2007.
-	Preliminary Agreement with respect to certain terms of a merger of affiliated companies Cambridge Electric, ComElectric and Canal Electric into Boston Edison; the merger will require approval by the MDTE. If approved, Boston Edison will be renamed "NSTAR Electric".
-	A sharing of costs and benefits resulting from NSTAR Electric's efforts to mitigate wholesale electric market inefficiencies.
-	The adoption of certain new Service Quality Index performance incentives and penalties.

This Settlement Agreement will provide Boston Edison with financial resources to continue with its important infrastructure improvements, while at the same time provide more certain levels of revenues than it otherwise would have available during the seven-year rate period.

Non-Cash Regulatory Asset and Capital Transfer

NSTAR was created in 1999 in connection with the merger of BEC Energy and Commonwealth Energy System. As of September 30, 2005, NSTAR changed the classification of its Goodwill to a Regulatory asset. This change was adopted to better align with Boston Edison's existing rate recovery mechanism that allows for the recovery of goodwill from its customers over 40 years. As a result of this change, NSTAR has reallocated a portion of the previously recorded goodwill from three other subsidiary companies: ComElectric, Cambridge Electric and NSTAR Gas to Boston Edison. This change was effective as of September 30, 2005 and was accounted for as a non-cash capital transfer to Boston Edison of $319 million from NSTAR. This transfer represents Boston Edison's proportionate share of goodwill that arose from the merger that created NSTAR in accordance with the 1999 Rate Order from the MDTE approving the merger.

In addition to this transfer of goodwill and its classification to a regulatory asset and in accordance with the requirements of SFAS 109, “Accounting for Income Taxes,” Boston Edison recognized $174.6 million of accumulated deferred income taxes related to this goodwill along with a corresponding regulatory asset as of September 30, 2005. The regulatory asset, representing the accumulated deferred income taxes, will be amortized over the remaining life of the regulatory asset -- goodwill (amounting to approximately $5.1 million annually) in accordance with NSTAR's merger rate order allowing full recovery of goodwill from ratepayers. This additional amortization expense will be entirely offset by a corresponding deferred income tax benefit.

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. Refer to Item 1A, Risk Factors, for more information.

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 accounting and reporting standards
-	new governmental regulations or changes to existing regulations that impose additional operating requirements or liabilities
-	changes in specific hazardous waste site conditions and the specific cleanup technology
-	impact of uninsured losses
-	changes in available information and circumstances regarding legal issues and the resulting impact on our estimated litigation costs
-	Impact of union contract negotiations
-	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. 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 judgments 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. Revenues related to the sale, transmission and distribution of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters that are read on a systematic basis throughout the month. Meters that are not read during a given month are estimated and trued-up to actual use in a future period. At the end of each month, amounts of energy delivered to customers since the date of the last billing date are estimated and the corresponding unbilled revenue is estimated. This unbilled electric revenue is estimated each month based on daily generation volumes (territory load), estimated line losses and applicable customer rates. Accrued unbilled revenues recorded in the accompanying Consolidated Balance Sheets as of December 31, 2005 and 2004 were $31.4 million and $28.4 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, 2005 and 2004, Boston Edison has recorded regulatory assets of $1.8 billion and $1.4 billion, respectively. 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. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.

c. Pension

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

In accordance with SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS 87) changes associated with these factors are not immediately recognized as pension 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 benefits in 2005, 2004 and 2003 that had a significant impact on recorded pension costs. As further described in Note H to the accompanying Consolidated Financial Statements, Boston Edison's discount rate at December 31, 2005 and 2004 was 5.75% to reflect market conditions and the characteristics of the pension obligation. The expected long-term rate of return on its pension plan assets for 2005 remained at 8.4% (net of plan expenses), the same as 2004. These assumptions will have a significant impact on reported pension costs in future years in accordance with the cost recognition approach of SFAS 87 described above. This impact, however, will be mitigated through Boston Edison’s regulatory accounting treatment of pension and postretirement benefit obligations other than pensions (PBOP) costs. (See further discussion of regulatory accounting treatment contained herewith.) 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 costs and funding requirements.

The Plan’s assets, which partially consist of equity investments, are affected by fluctuations in the financial markets. Fluctuations in market returns will affect pension costs in future periods.

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

(in thousands)
		Impact on
		Projected Benefit
	Change in	Obligation	Impact on 2005 Cost
Actuarial Assumption	Assumption	Increase/(Decrease)	Increase/(Decrease)
Pension:
Increase in discount rate	50 basis points	$(59,718)	$(4,213)
Decrease in discount rate	50 basis points	$ 62,789	$ 4,572
Increase in expected long-term
rate of return on plan assets	50 basis points	NA	$(4,410)
Decrease in expected long-term
rate of return on plan assets	50 basis points	NA	$ 4,410

NA - not applicable

Management evaluates the appropriateness of the discount rate through the modeling of a bond portfolio which approximates the Plan liabilities. Management further considers rates of high- quality corporate bonds of appropriate maturities as published by nationally recognized rating agencies consistent with the duration of the Company's plans.

In determining the expected long-term rate of return on plan assets, management considers past performance and economic forecasts for the types of investments held by the Plan as well as the target allocation for the investments over a 20-year time period. In 2005, management kept the expected long-term rate of return on plan assets at 8.4% as a result of the prevailing outlook for investment returns. This rate is presented net of both administrative expenses and investment expenses, which have averaged approximately 0.6% for both 2005 and 2004.

The expected long-term rate of return on Plan assets could vary from actual returns as well as the target allocation for investments overtime. As such, these fluctuations could impact Boston Edison's capital resources to meet its plan contributions.

As a result of the MDTE approved Pension and PBOP cost reconciliation rate adjustment mechanism tariff (PAM), NSTAR, through its regulated subsidiaries is authorized to recover its pension and PBOP expense through this reconciling rate mechanism. This PAM removes the volatility in earnings that could result from fluctuations in market conditions and plan assumptions.

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 contributed $75 million during 2005, $40 million of which was contributed in December 2005. This was incremental to the planned contributions for the year of $35 million. As a result, Boston Edison does not anticipate contributing to the Plan in 2006.

d. 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 operating 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), (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, 2005, the total remaining cost for decommissioning and/or security or protection of each nuclear unit is approximately as follows: $515.7 million for CY and $149.3 million for YA. Of these amounts, Boston Edison is obligated to pay $49 million towards the decommissioning of CY and $14.2 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 and cash flows. These estimates may be revised from time to time based on information available to the Yankee Companies regarding future costs.

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

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

CY is currently in litigation with Bechtel over the termination of its decommissioning contract. Additionally, Bechtel filed a complaint against CY asserting several claims as well as wrongful termination. Bechtel sought to garnish the decommissioning trust and related payments. In October 2004, Bechtel and CY entered into a stipulation under which Bechtel relinquished its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CY's real property in Connecticut with a book value of $7.9 million and the escrowing of portions of the sponsors' periodic payments, up to a total of $41.7 million, all of which the sponsors, which include Boston Edison, are scheduled to pay to CY through June 30, 2007. On January 27, 2006, the Connecticut Superior court issued a finding that the real property and the periodic payments were subject to attachment and garnishment, respectively, which is likely to result in the implementation of the stipulated escrowing arrangement. CY may appeal the Superior Court finding. The discovery phase in the litigation is drawing to a close and a trial has been scheduled for May 2006. Boston Edison cannot predict the timing or outcome of the litigation with Bechtel but does not expect a material impact on Boston Edison's financial position, results of operations or cash flows.

On November 22, 2005, FERC's Administrative Law Judge (ALJ) issued an Initial Decision (ID) that found in favor of CY on all imprudence claims, finding that no disallowance was warranted. The only adjustment the ID would make in CY's proposed decommissioning charges is with respect to the escalation rate used to factor the effects of inflation into the estimate. Because the ALJ found that CY had dispelled all claims of imprudence, the ALJ did not address any party's proposed disallowance whether on the grounds of imprudence or under the 2003 Settlement's budget incentive mechanism.

Under FERC's rules, the ID becomes final only if no party takes exception to it; if any party does take exception, the full FERC will review the ID, and FERC can reach different conclusions. CY expects that the interveners who unsuccessfully raised imprudence claims before the ALJ will pursue those claims before the full FERC.

During the course of carrying out the decommissioning work, YA has identified increases in the scope of soil remediation and certain other remediation required to meet environmental standards beyond the levels assumed in the 2003 Estimate. On November 23, 2005, YA submitted a filing to the FERC for adjustments to its Rate Schedules to revise the level of collections to recover the costs of completing the decommissioning of YA's retired nuclear generating plant (the 2005 Estimate). The schedule for the completion of physical work will need to extend until the end of August 2006 and the costs of completing decommissioning will be approximately $63 million greater than the estimate that formed the basis of the 2003 FERC settlement. Based on this allocation increase, Boston Edison is obligated to pay $6.0 million to the decommissioning of YA. Most of the cost increase relates to decommissioning expenditures that will be made during 2006, followed by a significant reduction in those charges during the years 2007 through 2010. On January 31, 2006, FERC issued an order accepting the rates for filing, effective February 1, 2006, subject to hearing and refund. FERC ordered the hearing held in abeyance pending the outcome of settlement procedures. Boston Edison cannot predict the timing or the ultimate outcome of these settlement discussions.

Derivative Instruments

Power Contracts

The electric distribution industry may contract to buy and sell electricity under option contracts, which allow the distribution company the flexibility to determine when and in what quantity to take electricity in order to align with its demand for electricity. These contracts would normally meet the definition of a derivative instrument requiring mark-to-market accounting. However, because electricity cannot be stored and utilities are obligated to maintain sufficient capacity to meet the electricity needs of its customer base, an option contract for the purchase of electricity typically qualifies for the normal purchases and sales exception as described in the FASB Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” and Derivative Implementation Group (DIG) interpretations and, therefore, does not require mark-to-market accounting. Boston Edison accounts for its energy contracts in accordance with SFAS No. 133 and SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities."

Boston Edison has long-term purchase power agreements that are used primarily to meet its customer obligations. The majority of these agreements are not reflected as an asset or liability on the accompanying Consolidated Balance Sheets as they qualify for the normal purchases and sales exception. However, based on SFAS 133 and DIG interpretations, Boston Edison, as of December 31, 2004, had one remaining contract that was recorded at fair value on the accompanying Consolidated Balance Sheets. On March 1, 2005, Boston Edison closed on a securitization financing for $265.5 million to, in part, finance the buy-out of this remaining contract that was classified as a derivative instrument at December 31, 2004. This contract had an aggregate fair value of approximately $235 million at December 31, 2004 and was therefore removed as a derivative instrument from Deferred credits - Power contracts, along with the offsetting regulatory asset, on the accompanying Consolidated Balance Sheets. The securitization debt obligation was recorded along with an offsetting regulatory asset to reflect the future recovery of the debt obligation through its transition charge. At December 31, 2005, Boston Edison does not have any contracts that continue to be classified as derivative instruments. Refer to the accompanying Consolidated Financial Statements, Note L, for more detail on the buy-out of certain purchase power contracts.

Asset Retirement Obligations

In March 2005, the FASB issued Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143" (FIN 47), "Accounting for Asset Retirement Obligations” (SFAS 143). In 2003, NSTAR adopted SFAS 143 that established accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. FIN 47 clarifies when an entity would be required to recognize a liability for the fair value of an ARO that is conditional on a future event if the liability's fair value can be reasonably estimated. Uncertainty surrounding the timing and method of settlement that may be conditional on events occurring in the future are factored into the measurement of the liability rather than the existence of the liability.

Boston Edison adopted FIN 47 at December 31, 2005, as required. The recognition of an ARO within its regulated utility business has no impact on Boston Edison's earnings. In accordance with SFAS 71, Boston Edison established a regulatory asset to recognize future recoveries through depreciation rates for the recorded ARO. Boston Edison has identified several plant assets in which this condition exists and is related to plant assets containing asbestos materials. As a result, in December 2005, Boston Edison recognized an asset retirement cost of $0.4 million as an increase in utility property, an asset retirement liability of $8.5 million and a regulatory asset of $8.1 million.

For comparative purposes, the pro forma ARO that would have been recognized in accordance with FIN 47 as of December 31, 2004 and January 1, 2004 would have amounted to $8.0 million and $7.6 million, respectively.

The ultimate cost to remove utility plant from service (cost of removal) is recognized as a component of depreciation expense in accordance with Boston Edison's approved regulatory treatment. As of December 31, 2005 and 2004, the estimated amount of the future cost of removal included in regulatory liabilities was approximately $150 million and $155 million, respectively, based on the estimated cost of removal component in current depreciation rates.

Variable Interest Entities

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

Boston Edison has two wholly owned special purpose subsidiaries, BEC Funding LLC, established in 1999, and BEC Funding II, LLC, established in 2004, to undertake the sale of $725 million and $265.5 million, respectively, in notes to a special purpose trust created by two Massachusetts state agencies. Boston Edison consolidates each of these entities. As part of Boston Edison’s assessment of FIN 46R and, for compliance at December 31, 2005 or 2004, Boston Edison reviewed the substance of these entities to determine if it is still proper to consolidate these entities. Based on its review, Boston Edison has concluded that BEC Funding, LLC and BEC Funding II, LLC are VIEs and should continue to be consolidated by Boston Edison.

For the March 31, 2004 effective date of FIN 46R, Boston Edison evaluated other entities with which it conducts significant transactions, including companies that supply power to Boston Edison through its purchase power agreements. Boston Edison determined that it is possible that two of these companies may be considered VIEs. In order to determine if these counterparties are VIEs and if Boston Edison is the primary beneficiary of these counterparties, Boston Edison concluded that it needed more information from the entities. Boston Edison attempted to obtain the information required and requested, in writing, that these entities provide the Company with the necessary information. However, both of the entities have indicated that they will not provide the requested information as they are not contractually obligated to provide such confidential information. Since Boston Edison was unable to obtain the necessary information and, as allowed under a scope exception in FIN 46R, the accompanying Consolidated Financial Statements do not reflect the consolidation of any entities with which Boston Edison has a purchase power agreement.

Subsequent to the March 31, 2004 effective date, Boston Edison executed purchase power buy-out or restructuring agreements with both of the entities from which Boston Edison attempted to obtain additional information in order to determine if these entities are VIEs. These buy-out or restructuring agreements received regulatory approval in January 2005. Refer to Consolidated Financial Statements, Note L, for more detail on the purchase power buy-out agreements. As a result, Boston Edison will no longer pursue obtaining the necessary information to determine whether it has a potential variable interest in these entities.

New Accounting Standards

In May 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections." This Standard which is effective January 1, 2006, changes the requirements for the accounting for and reporting of accounting changes and error corrections. The Standard establishes retrospective application as the required method for reporting a change in accounting principle rather than reporting a cumulative effect of change in accounting principle. Retrospective application requires the application of the new accounting principle to prior periods as if that principle had always been used. Accordingly, Boston Edison will adopt this Standard.

Rate and Regulatory Proceedings

a. Service Quality Indicators

Service quality indicators (SQI) 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.

Boston Edison monitors its service quality continuously to determine its contingent liability. If it is probable that a liability has been incurred and is estimable, a liability is 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 that the MDTE issues an order determining the amount of any such liability.

On March 1, 2005, Boston Edison filed its 2004 Service Quality Report with the MDTE that demonstrated the Company achieved sufficient levels of reliability and performance; the reports indicate that no penalty was assessed for 2004. On December 30, 2005, the MDTE issued a formal approval of this filing.

As of December 31, 2005, Boston Edison’s 2005 performance has exceeded the applicable established benchmarks such that no liability has been accrued for 2005. Since 2001, Boston Edison has not been in a penalty position. However, the past and current performance is not indicative of future results.

In late 2004, the MDTE initiated a proceeding to potentially modify the service quality indicators for all Massachusetts utilities. Until any modification occurs, the current SQI measures will remain in place. Boston Edison cannot predict the outcome or timing of this proceeding.

The Settlement Agreement approved by the MDTE on December 30, 2005, established an additional performance measure applicable to Boston Edison. This new measure establishes a performance benchmark relating to poor performing circuits, with a maximum penalty or incentive of up to approximately $500,000.

b. Electric Rates

Electric distribution companies in Massachusetts have been required to obtain and resell power to retail customers through either standard offer or default service for those who choose not to buy energy from a competitive energy supplier. Standard offer service ended on February 28, 2005 and effective March 1, 2005, all customers who had not chosen to receive service from a competitive supplier were provided default service, subsequently renamed “basic service.” Basic service rates are reset every six months (every three months for large commercial and industrial customers). The price of basic service is intended to reflect the average competitive market price for power. As of December 31, 2005, 2004 and 2003, customers of Boston Edison had approximately 26%, 25% and 27%, respectively, of their load requirements provided by competitive suppliers.

On December 30, 2005, the MDTE approved a rate Settlement Agreement between the Attorney General of Massachusetts, NSTAR and several interveners effective January 1, 2006. Refer to the "Rate Settlement Agreement" section of this MD&A.

In December 2005, Boston Edison filed proposed transition rate adjustments for 2006, including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2005. The MDTE subsequently approved tariffs for Boston Edison effective January 1, 2006. The filings are to be updated in March 2006 to reflect final 2005 costs and revenues which are subject to final reconciliation. As part of the rate Settlement Agreement approved by the MDTE on December 30, 2005, transition rates are further impacted by a reduction of approximately $15 million of the total NSTAR Electric $20 million reduction effective January 1, 2006 and approximately $23 million of the total NSTAR Electric $30 million reduction on May 1, 2006 and are deferred with carrying charges at a rate of 10.88%.

In December 2004, Boston Edison filed proposed transition rate adjustments for 2005, including a preliminary reconciliation of transition, transmission, standard offer and basic service costs and revenues through 2004. The MDTE approved tariffs for Boston Edison effective January 1, 2005. The filings were updated in February 2005 to reflect final 2004 costs and revenues. The filings are subject to annual review and reconciliation.

Settlement discussions for the reconciliation of Boston Edison's 2004 costs for transition, transmission, standard offer, basic service and PAM have been delayed and will be combined with the settlement of 2005 costs or decided by the MDTE in a future hearing. Boston Edison cannot predict the timing or the ultimate outcome of these settlement discussions or adjustments, but does not anticipate a material impact to the Company's financial position, results of operations or cash flows.

c. Wholesale Market Rule Changes

Locational Installed Capacity (LICAP)

On March 23, 2005, the FERC unanimously approved an Independent System Operator-New England (ISO-New England) plan to implement LICAP, a new market rule designed to compensate wholesale generators for their capacity with an implementation date of January 1, 2006. FERC subsequently revised this date to no earlier than October 2006. The new LICAP rules require electric load serving entities (LSE), like NSTAR Electric, to utilize capacity within the zones where load is served. The current market structure allows capacity located anywhere in New England to count towards an LSE's obligation, regardless of load zone. Boston Edison’s service territory covers two of the five capacity zones in New England; Northeastern Massachusetts (NEMA) and Rest of Pool (ROP). NEMA is import-constrained and could potentially see higher capacity prices than the ROP. The majority of NSTAR Electric's customers are in the NEMA load zone. At this point, it is likely that the completion of NSTAR Electric's 345kV transmission project will reduce transmission constraints causing capacity prices between NEMA and ROP to converge. This could ultimately render this locational aspect of LICAP a minimal factor for NSTAR Electric's customers. However, since the new market rules require that a certain amount of capacity be procured in the NEMA zone, these requirements could impact pricing for capacity in the NEMA zone.

Additionally, several generators in the NEMA zone have filed with the FERC for cost of service-type agreements called Reliability Must Run agreements for the recovery of their costs prior to the implementation of LICAP. The new LICAP rules are likely to increase overall capacity pricing levels in New England. Since the New England market as a whole is currently in a surplus position, capacity trades at a relatively low price. One of the goals of LICAP is to provide a higher level of compensation to generators than what is currently being earned in this surplus market. NSTAR is opposed to LICAP as it will likely increase the price of power to NSTAR Electric's customers without any assurance that new capacity will be built. As a result, NSTAR (and other parties) have appealed the FERC's LICAP decision in federal court. Additionally, while LICAP has been approved by FERC, the specific parameters of the capacity pricing mechanism are still being contested at FERC. A final decision on these matters is expected sometime in 2006. On October 21, 2005, FERC issued an Interim Order Regarding Settlement Procedures and Directing Compliance Filing. In this Order, the FERC gives the parties in this proceeding a further opportunity to pursue settlement on an alternative to the LICAP mechanism. FERC further directed that a settlement judge be appointed to manage the process. On January 31, 2006, this Settlement Judge, along with other parties, requested from the FERC an extension to file the Settlement Agreement and accompanying documents within 34 days. On March 6, 2006, a Settlement Agreement was filed with FERC and will remain open until reply comments are filed on April 12, 2006 by the parties. Boston Edison cannot predict the actual impact these changes will have on Boston Edison and its customers, but expects all costs incurred to be fully recoverable. In addition, the Company's December 30, 2005 rate Settlement Agreement provides an incentive mechanism for the recovery of litigation costs associated with Boston Edison’s efforts to reduce wholesale energy and capacity costs and sharing of customer benefits realized from those efforts with the potential for the Company to retain 25% of any resulting savings.

Regional Transmission Organization (RTO)

On March 24, 2004, the FERC decided to schedule hearings for a joint return on equity (ROE) filing made by participating New England Transmission Owners, including NSTAR Electric. The joint ROE filing among the Transmission Owners was made concurrently in connection with the proposed formation of an RTO by the Transmission Owners and ISO-NE and is an important and integral component of the agreement to form an RTO for the New England region. Among other things, the filing requested an increase in the base ROE component of regional and local transmission rates to a single ROE of 12.8% for all regional and local transmission rates, a 50 basis point adder to reward RTO participation, and a 100 basis point increase in regional rates as an incentive to build new transmission facilities. FERC accepted the 50 basis point adder for regional rates, and set for hearing the base ROE and the 100 basis point incentive adder for new transmission. Settlement negotiations before an administrative law judge were unsuccessful and hearings were held in early 2005. As a result of these hearings, on May 27, 2005, an initial decision was reached. The judge found that the base ROE should be 10.72% and that the 100 basis point adder for new transmission facilities should only apply to projects where innovative and less expensive technology is used. Appeal briefs by all parties, including the Transmission Owners, were filed with the full Commission on June 27, 2005, and are currently awaiting the FERC's final decision.

In November 2005, as directed by the Energy Policy Act of 2005, FERC proposed incentives to facilitate the maintenance and expansion of the interstate transmission system. FERC's proposals are intended to ensure that the return on equity is sufficient to attract new transmission investment and to apply "incentive based" ratemaking that would ultimately accrue to the benefits of customers by ensuring reliability and by reducing the cost of delivered power. The final rulemaking will be issued prior to August 31, 2006.

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

Sale of Property

On April 7, 2004, Boston Edison sold a parcel of land in the City of Newton, Massachusetts for $15.1 million; the net proceeds from the sale were used to reduce Boston Edison's transition charge. The sale and the regulatory treatment of the proceeds were approved by the MDTE. As a result, this transaction had no impact on 2004 earnings.

Other Legal Matters

Results of Operations

The following section of MD&A compares the results of operations for each of the two fiscal years ended December 31, 2005 and 2004 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.

2005 compared to 2004

Earnings and operations overview

Net income was $131.2 million for 2005 compared to $134.1 million for 2004. Factors that contributed to the $2.9 million, or 2.2% decrease in 2005 net income include:

-	Higher operations and maintenance expense due to costs associated with
	-	severe storms (approximately $5.6 million)
	-	facilities consolidation (approximately $1.1 million)
	-	an environmental site clean-up Settlement Claim (approximately $4.7 million)
	-	a work stoppage by union employees (approximately $2 million)
	-	increased bad debt expense (approximately $2 million)
-	Reduced mitigation incentive revenues (approximately $2.9 million)
-	Increased depreciation due to higher plant balance (approximately $3.7 million)

These decreases were partially offset by:

-		Higher distribution revenue due to a 2.6% increase in sales ($12.5 million)
-		Higher electric transmission rates due to FERC approval of the inclusion of 50% of transmission CWIP in rate base ($8.3 million)
-		Higher incentive entitlement revenues resulting from the Company's demand-side management programs ($0.7 million)

Energy sales and weather

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

	Years ended December 31,
		2005	2004	% Change
Retail Electric Sales - MWH
Residential		4,428,754	4,283,560	3.4%
Commercial		9,794,282	9,505,374	3.0%
Industrial		1,234,352	1,267,230	(2.6)%
Other		141,165	144,639	(2.4)%
Total retail sales		15,598,553 =======	15,200,803 =======	2.6% ====

In terms of customer sector characteristics, industrial sales are less sensitive to weather while residential and commercial sales are influenced by temperature extremes. The overall warmer weather in 2005 caused residential air conditioning use to rise and significantly contributed to the increase in electric sales. Additionally, the commercial sector has continued to expand and that has resulted in additional energy use. Electric residential and commercial customers represented approximately 28% and 63%, respectively, of Boston Edison's total sales mix for 2005 and provided 39% and 55% of distribution revenues, respectively. Refer to the "Operating revenues" section below for a more detailed discussion. Industrial sales are primarily influenced by local economic conditions, and sales to these customers reflect a sluggish economic environment and decreased manufacturing production.

Boston Edison forecasts its electric sales based on normal weather conditions. Therefore, 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.

			Normal
			30-Year
	2005	2004	Average

Heating degree-days	5,875	5,743	5,630
Percentage (warmer) colder than prior year	2.3%	(4.6)%
Percentage colder than 30-year average	4.4%	1.5%

Cooling degree-days	894	632	777
Percentage warmer (cooler) than prior year	41.5%	(16.3)%
Percentage warmer (cooler) than 30-year average	15.1%	(18.7)%

Weather conditions impact electric sales in Boston Edison’s service area. The first quarter of 2005 was warmer than the same period in 2004, followed by a cooler spring for the second quarter. The warmer than prior year third quarter resulted in increased air conditioning demand that preceded a slightly colder fourth quarter of 2005. The comparative information above relates to heating and cooling degree-days for 2005 and 2004 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 2005 increased $207.3 million, or 12.2%, compared to 2004, and consisted of the following major components:

(in thousands)						Increase/(Decrease)
		2005		2004		Amount		Percent

Retail distribution and transmission	$	631,457	$	621,520	$	9,937		1.6%
Energy, transition and other		1,171,682		976,749		194,933		20.0%
Total retail revenues		1,803,139		1,598,269		204,870		12.8%
Wholesale revenues		9,687		16,955		(7,268	)	(42.9)%
Other revenues		100,227		90,569		9,658		10.7%
Total revenues	$	1,913,053 =======	$	1,705,793 =======	$	207,260 ======		12.2% ====

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. In addition to a 2.6% increase in retail MWH sales, substantially all in the residential and commercial sectors, there were increased rates for the recovery of energy costs.

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.

Energy, transition and other revenues primarily represent charges to customers for the recovery of costs incurred by the Company in order to acquire energy supply on behalf of its customers and a transition charge for recovery of the Company's prior investments in generating plants and the costs related to long-term power contracts. The energy revenues relate to customers being provided energy supply under either standard offer or default service. The retail revenues related to basic service 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. The increase in energy, transition and other revenues of $194.9 million is primarily attributable to higher rates for basic service.

Wholesale revenues relate to services provided to municipalities and certain other governmental authorities. The decrease in 2005 wholesale revenues reflects the expiration of a wholesale power supply contract in 2004. As of November 2005, Boston Edison no longer has 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.

Other revenues were $100.2 million in 2005 compared to $90.6 million in 2004, an increase of $9.6 million, or 10.6%. This increase primarily relates to the increase in rental revenues from electric property due to expansion of the Company's transmission facilities.

Operating expenses

Purchased power costs were $1,037.9 million in 2005 compared to $882.8 million in 2004, an increase of $155.1 million, or 17.6%. The increase is primarily due to the higher cost of energy. Boston Edison adjusts its electric rates to collect the costs related to energy supply from customers on a fully reconciling basis. Due to the rate adjustment mechanisms, changes in the amount of energy supply expense have no impact on earnings.

Operations and maintenance expense was $240.3 million in 2005 compared to $221.4 million in 2004, an increase of $18.9 million, or 8.5%. This increase primarily reflects costs associated with: a work stoppage by union employees (approximately $2 million); severe storms (approximately $5.6 million); facilities consolidation (approximately $1.1 million); a settlement of an environmental claim (approximately $4.7 million); higher bad debt expense (approximately $2 million) and higher employee benefit costs.

Depreciation and amortization expense was $215 million in 2005 compared to $176.0 million in 2004, an increase of $39 million, or 22%. The increase reflects higher depreciable distribution and transmission plant in service, and increased amortization related to the higher amount of securitized regulatory assets. This increase also reflects the increased amortization of the regulatory asset - goodwill asset tax component. This increase in regulatory asset-goodwill amortization is entirely offset by a corresponding deferred income tax credit to expense. Refer to Note C for additional information.

Demand side management (DSM) and renewable energy programs expense was $46.4 million in 2005 compared to $45.2 million in 2004. The levels of these expenses are consistent with the collection of conservation and renewable energy revenues. These costs are collected from customers on a fully reconciling basis plus a small incentive return.

Property and other taxes were $76.7 million in 2005 compared to $76.8 million in 2004, a decrease of $0.1 million, or 0.1%. This slight decrease was due to lower overall municipal property taxes resulting from previous property sales.

Income taxes attributable to operations were $83.6 million in 2005 compared to $88.5 million in 2004, a decrease of $4.9 million, or 5.5%, primarily due to the amortization of a deferred tax liability recorded in 2005 related to the goodwill asset. This results in the recording of deferred income tax credit which is entirely offset in higher goodwill amortization expense. Also contributing to this decrease is the impact of lower pretax income in 2005.

Interest charges

Interest on long-term debt and transition property securitization certificates was $85.6 million in 2005 compared to $78.3 million in 2004, an increase of $7.3 million, or 9.3%. The increase in interest expense primarily reflects:

-		Higher interest costs in 2005 of $4.3 million on Boston Edison's $300 million ten-year fixed rate 4.875% Debentures issued on April 16, 2004
-		Additional interest costs of $4.2 million associated with transition property securitization. Securitization interest represents interest on securitization certificates of BEC Funding, LLC and BEC Funding II, LLC collateralized by the future income stream associated primarily with Boston Edison's stranded costs. The future income stream was assigned to these companies by Boston Edison.

These increases were partially offset by:
-		The absence in 2005 of expense of nearly $3 million related to the retirement of Boston Edison's $181 million 7.80% Debentures on March 15, 2004.

Short-term and other interest expense was $2.1 million in 2005 compared to $5.6 million in 2004, a decrease of $3.5 million, or 63%. The decrease in short-term and other interest expense relates to lower interest costs of $5.3 million on regulatory deferrals offset by higher short-term debt borrowing costs of $1.8 million, primarily reflective of a 223 basis point increase in 2005 weighted average borrowing rates from 1.49% in 2004 to 3.72% in 2005.

Allowance for funds used during construction was $2.6 million in 2005 compared to $0.6 million in 2004, an increase of $2.0 million, primarily due to a higher average balance of construction work in progress during the year. Also impacting is a 223 basis point increase in short-term weighted average borrowing rates.

Other Events

Borrowing Arrangements

Boston Edison has approval from the FERC to issue short-term debt securities from time to time on or before December 31, 2006, with maturity dates no later than December 31, 2007, in amounts such that the aggregate principal does not exceed $450 million at any one time. Boston Edison has a five year, $350 million revolving credit agreement that expires in November 2009. However, unless Boston Edison receives necessary approvals from the MDTE, the credit agreement will expire 364 days from the date of the first draw under agreement. At December 31, 2005 and 2004, there were no amounts outstanding under the current and previous revolving credit agreement. This credit facility serves as backup to Boston Edison's $350 million commercial paper program that had a $197.0 million and $46.5 million balance at December 31, 2005 and 2004, respectively. Under the terms of the current agreement, Boston Edison is required to maintain a consolidated maximum total debt to capitalization ratio of not greater than 65% at all times, excluding Transition Property Securitization Certificates, and excluding Accumulated other comprehensive income (loss) from Common equity. The previous agreement required a total debt to capitalization ratio of not greater than 60%. At December 31, 2005 and 2004, Boston Edison was in full compliance with its covenants in connection with its short-term credit facilities as the ratios were 45.9% and 53.1%, respectively.

Capital Spending

In the first quarter of 2005, Boston Edison began construction on a 345kV transmission line that will connect Stoughton, Massachusetts, a southern suburb of Boston, to South Boston. This transmission line is expected to assure continued reliability of electric service and improve power import capacity in the Northeast Massachusetts area. This project is expected to be placed in service during the summer of 2006. The cost of the project is expected to be shared by all of New England and will be recovered by Boston Edison through regional and retail transmission rates.

Performance Assurances from Electricity Agreements

Boston Edison has entered into short-term power purchase agreements to meet its entire basic service supply obligation, other than to its largest customers, for the period January 1, 2006 through June 30, 2006 and for 50% of its obligation, other than to these large customers, for the second half of 2006. Boston Edison has entered into short-term power purchase agreements to meet its entire basic service supply obligation for large customers through March 2006. 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. Most of Boston Edison’s power suppliers are either investment grade companies or 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. 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 timeframes, 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 NSTAR receives a downgrade, the 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 letters of credit, surety bonds and other guarantees.

At December 31, 2005, outstanding guarantees totaled $20.8 million as follows:

(in thousands)
Letters of Credit	$	7,500
Surety Bonds		6,673
Other Guarantees		6,660
Total Guarantees	$	20,833 =====

In May 2005, Boston Edison issued a $7.5 million standby letter of credit to the general contractor of Boston Edison's 345kV project. The amount of the standby letter of credit was reduced to $4.5 million on February 1, 2006. The contractor will be able to draw upon the letter of credit if Boston Edison does not comply with the payment terms of the respective executed construction agreement, signed by both parties. Boston Edison believes that it is very unlikely that a draw will be made on the standby letter of credit.

As of December 31, 2005, 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 the Company's workers’ compensation self-insurance program.

Boston Edison has also issued $6.7 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.

Contingencies

Environmental Matters

Boston Edison faces possible liabilities as a result of involvement in multi-party disposal sites, state-regulated 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 the majority of these sites.

During the second quarter of 2005, the Massachusetts Supreme Judicial Court (SJC) issued its decision in one of the environmental contamination matters. In 2004, a Superior Court had issued a decision favorable to Boston Edison that put the burden of proof on the plaintiffs to determine Boston Edison's liability for contamination. The SJC's decision reversed the Superior Court's 2004 ruling and held that the plaintiffs in this matter are allowed to seek joint and several liability against the defendants, including Boston Edison. The case was remanded back to the Superior Court for trial. On October 6, 2005, Boston Edison reached a settlement in principle with the plaintiffs in this matter. It is anticipated that the appropriate settlement documents will be finalized in March 2006 and filed with the Superior Court shortly thereafter. The Settlement is subject to a 90-day public comment period at which point we expect the Superior Court to approve and enter final judgment. Boston Edison anticipates paying within 30 days of the final judgment approximately $8.6 million which approximates the amount previously reserved for this matter. Boston Edison will vigorously attempt to recover monies from the other responsible third parties, including recovery from its insurance carrier.

As of December 31, 2005 and 2004, Boston Edison had reserves of $10.2 million and $3.4 million, respectively, for all potential environmental sites, including the site specified in the paragraph above. This estimated recorded liability is based on an evaluation of all currently available facts with respect to all of its sites. In addition, based on a legal opinion from the Company's environmental counsel, it is probable that Boston Edison will recover, at a minimum, approximately $2 million from other parties. As a result, Boston Edison recorded a receivable in the second quarter that will ultimately offset the Company's obligation. Management believes that the ultimate disposition of this matter will not have a material adverse impact on Boston Edison’s results of operation, cash flows or its financial position.

Estimates related to environmental remediation costs are reviewed and adjusted 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, results of operations or cash flows.

Employees and Employee Relations

Boston Edison does not have any employees. All labor services are provided by employees of NSTAR Electric & Gas. As of December 31, 2005, NSTAR had approximately 3,050 employees, including approximately 2,150, or 70%, who are represented by units covered by separate collective bargaining contracts.

NSTAR's labor contract with Local 369 of the Utility Workers Union of America, AFL-CIO, expired on May 15, 2005. After a brief strike, on May 29, 2005, NSTAR management and union officials agreed upon a new four year contract expiring June 1, 2009. The union members, which represent approximately 1,850 employees, ratified the contract on May 31, 2005. Approximately 250 employees, represented by Local 12004, United Steelworkers of America, AFL-CIO, have a contract that expires on March 31, 2006. Management and Union officials are currently negotiating a new contract. Management cannot predict the outcome of this negotiation.

Management believes it has satisfactory relations with its employees.

Fair Value of Financial Instruments

Carrying amounts and fair values of long-term indebtedness (excluding notes payable, including current maturities) as of December 31, 2005 and 2004, were as follows:

	2005		2004
	Carrying	Fair		Carrying	Fair
(in thousands)	Amount	Value		Amount	Value
Long-term indebtedness	$1,369,182	$1,379,350		$1,302,030	$1,373,170
(including current maturities)

As discussed in Item 7A below, Boston Edison's exposure to financial market risk results primarily from fluctuations in interest costs.

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 rate-making mechanisms that allow for the recovery of energy supply costs from customers, who made commodity purchases from Boston Edison rather than from the competitive market. All energy supply costs incurred by Boston Edison to provide electricity for retail customers purchasing basic service are recovered on a fully reconciling basis.

However, Boston Edison’s exposure to financial market risk results primarily from fluctuations in interest rates. 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 5.47% and 5.58% in 2005 and 2004, respectively.

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Report of Independent Registered Public Accounting Firm

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 present fairly, in all material respects, the financial position of Boston Edison Company and its subsidiaries (the "Company") at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 Item15(a)2 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 the Company’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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit 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.

/s/ PRICEWATERHOUSECOOPERS LLP

Boston, Massachusetts
March 7, 2006

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Item 8. Financial Statements and Supplementary Data

Boston Edison Company
Consolidated Statements of Income

		Years ended December 31,
		2005			2004			2003
		(in thousands)

Operating revenues	$	1,913,053		$	1,705,793		$	1,699,184

Operating expenses:
Purchased power		1,037,911			882,755			874,441
Operations and maintenance		240,317			221,439			224,869
Depreciation and amortization		214,740			175,990			170,924
Demand side management and
renewable energy programs		46,431			45,212			45,512
Property and other taxes		76,729			76,787			72,174
Income taxes		83,578			88,531			89,957
Total operating expenses		1,699,706			1,490,714			1,477,877

Operating income		213,347			215,079			221,307

Other income (deductions):
Other income, net		4,326			3,136			2,374
Other deductions, net		(1,229	)		(865	)		(801	)
Total other income, net		3,097			2,271			1,573

Interest charges:
Long-term debt		53,291			50,123			52,684
Transition property securitization		32,338			28,150			32,715
Short-term and other		2,132			5,565			7,775
Allowance for borrowed funds used
during construction (AFUDC)		(2,565	)		(618	)		(1,212	)
Total interest charges		85,196			83,220			91,962

Net income	$	131,248 =======		$	134,130 =======		$	130,918 ======

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 Retained Earnings

		Years ended December 31,
		2005		2004		2003
		(in thousands)

Balance at the beginning of the year	$	566,161	$	502,991	$	475,993
Add:
Net income		131,248		134,130		130,918
Subtotal		697,409		637,121		606,911
Deduct:
Dividends declared:
Dividends to Parent		92,000		69,000		101,960
Preferred stock		1,960		1,960		1,960
Subtotal		93,960		70,960		103,920
Balance at the end of the year	$	603,449 ======	$	566,161 ======	$	502,991 ======

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

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Boston Edison Company
Consolidated Balance Sheets

		December 31,
		2005				2004
		(in thousands)
Assets
Utility plant in service, at original cost	$	3,066,267			$	2,944,725
Less: accumulated depreciation		705,768		2,360,499		677,398			2,267,327
Construction work in progress				175,785				71,484
Net utility plant				2,536,284				2,338,811
Equity and other investments				9,092				9,037
Current assets:
Cash and cash equivalents		10,148				6,468
Restricted cash		4,943				3,616
Accounts receivable -
net of allowance of $14,384 and
$14,091 in 2005 and 2004, respectively		160,167				167,157
Accounts receivable - Affiliates		-				16,332
Accrued unbilled revenues		31,415				28,444
Regulatory assets		260,943				188,862
Inventory, at average cost		17,246				12,883
Other		8,210		493,072		14,070			437,832
Deferred debits:
Regulatory assets				1,494,148					1,256,154
Prepaid pension				346,889					297,746
Other				12,136					13,828
Total assets			$	4,891,621 ======			$		4,353,408 ======

Capitalization and Liabilities
Common equity:
Common stock, par value $1 per share,
100 shares authorized; 75 shares
issued and outstanding	$	-			$	-
Premium on common shares		597,843				278,795
Retained earnings		603,449		1,201,292		566,161			844,956
Cumulative non-mandatory redeemable preferred
stock				43,000					43,000
Long-term debt				850,378					851,547
Transition property securitization				455,424					308,748
Current liabilities:
Long-term debt		688				100,687
Transition property securitization		62,692				41,048
Notes payable		197,000				46,500
Power contracts		131,424				121,033
Accounts payable		159,786				89,819
Payable to affiliates		21,664				-
Accrued interest		9,853				10,125
Deferred income taxes		16,813				16,662
Other		36,576		636,496		30,389			456,263
Deferred credits:
Accumulated deferred income taxes and
unamortized investment tax credits				908,450					664,261
Power contracts				475,797					795,722
Regulatory liability - cost of removal				149,873					155,497
Payable to Affiliates				127,441					150,634
Other				43,470					82,780

Commitments and contingencies

Total capitalization and liabilities			$	4,891,621 ======			$		4,353,408 ======

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

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Boston Edison Company
Consolidated Statements of Cash Flows

		Years ended December 31,
		2005			2004			2003
		(in thousands)
Operating activities:
Net income	$	131,248		$	134,130		$	130,918
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization		214,740			175,990			172,303
Deferred income taxes and investment tax credits		67,554			45,217			46,980
Allowance for borrowed funds used during construction (AFUDC)		(2,565	)		(618	)		(1,212	)
Effect of purchase power contract buy-out		(342,281	)		-			-
Net changes in:
Accounts receivable and accrued unbilled revenues		11,814			(18,670	)		5,886
Inventory, at average cost		(4,363	)		427			(19	)
Accounts payable		39,739			(29,194	)		(31,037	)
Other current assets and liabilities		(50,160	)		(13,261	)		33,985
Deferred debits and credits, net		60,950			47,874			(75,855	)
Net cash provided by operating activities		126,676			341,895			281,949

Investing activities:
Plant expenditures (excluding AFUDC)		(260,160	)		(199,826	)		(177,249	)
Proceeds on sale of property, net		-			14,252			-
Increase in restricted cash		(1,327	)		-			-
Investments		342			619			1,936
Net cash used in investing activities		(261,145	)		(184,955	)		(175,313	)

Financing activities:
Long-term debt issuance		-			300,000			-
Issuance of transition property securitization		265,500			-			-
Transition property securitization redemptions		(81,410	)		(68,741	)		(68,014	)
Financing costs		(2,481	)		(1,851	)		-
Long-term debt redemption		(100,000	)		(181,346	)		(152,838	)
Net change in notes payable		150,500			(136,000	)		182,500
Dividends paid		(93,960	)		(70,960	)		(103,920	)
Net cash used in financing activities		138,149			(158,898	)		(142,272	)
Net increase (decrease) in cash and cash equivalents		3,680			(1,958	)		(35,636	)
Cash and cash equivalents at the beginning of the year		6,468			8,426			44,062
Cash and cash equivalents at the end of the year	$	10,148 ======		$	6,468 ======		$	8,426 =====

Cash paid during the period for:

Interest, net of amounts capitalized	$	84,040 ======		$	76,225 =====		$	87,008 =====

Income taxes paid	$	8,903 ======		$	89,295 =====		$	8,782 =====

Non-cash investing activity:

Non-cash capital transfer (Note C)	$	319,000 =====		$	- ====		$	- ====

Deferred debit regulatory asset - goodwill (Note C)	$	445,173 =====		$	- ====		$	- ====

Non-cash plant additions	$	30,228 =====		$	- ====		$	- ====

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 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. Boston Edison serves approximately 700,000 electric distribution customers in the City of Boston and 39 surrounding communities. NSTAR is a holding company engaged through its subsidiaries in the energy delivery business serving approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric distribution customers in 81 communities and approximately 300,000 natural gas distribution customers in 51 communities. NSTAR’s retail distribution 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 distribution companies collectively operate as “NSTAR Electric.” Reference in this report to “NSTAR” shall mean NSTAR or NSTAR and its subsidiaries as the context requires. Reference in this report to “NSTAR Electric” shall mean Boston Edison, ComElectric and Cambridge Electric together. NSTAR has a service company that provides management and support services to substantially all NSTAR subsidiaries - NSTAR Electric & Gas Corporation (NSTAR Electric & Gas).

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. As of November 1, 2005, Boston Edison no longer has wholesale electric supply contracts.

2. Basis of Consolidation and Accounting

The accompanying Consolidated Financial Statements reflect the results of operations, retained earnings, financial position and cash flows of Boston Edison and its subsidiaries, Harbor Electric Energy Company (HEEC), BEC Funding LLC and BEC Funding II, LLC. All significant intercompany transactions have been eliminated in consolidation. Certain immaterial reclassifications have been made to the prior year amounts to conform with 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). Boston Edison is subject to the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). The application of SFAS 71 results in differences in the timing of recognition of certain expenses from those of other businesses and industries. The distribution and transmission businesses remain subject to rate-regulation and continue to meet the criteria for application of SFAS 71. Refer to Notes C and D 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.

3. Revenues

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.

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.

The following is a summary of utility property and equipment, at cost, at December 31:

(in thousands)		2005		2004
Electric -
Transmission	$	563,353	$	543,774
Distribution		2,369,682		2,256,873
General		133,232		144,078
Electric utility plant in service	$	3,066,267 =======	$	2,944,725 =======

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 2.91%, 2.85% and 2.86% in 2005, 2004 and 2003, respectively. The rates include a cost of removal component, which is collected from customers. Depreciation expense on utility plant for 2005, 2004 and 2003 was $89.7 million, $86 million and $83 million, respectively.

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 and amortized as an addition to interest expense over the life of the original or replacement debt. Costs related to preferred stock issuances and redemptions are reflected as a direct reduction to retained earnings upon redemption or over the average life of the replacement preferred stock series as applicable.

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 2005, 2004 and 2003 were 3.72%,1.40% and 1.40%, respectively, and represented only the costs of short-term debt. The 2005 rate increase is directly related to an increase in short-term borrowing rates.

8. Cash, Cash Equivalents and Restricted Cash

Cash, cash equivalents and restricted cash at December 31, 2005 and 2004 are comprised of liquid securities with maturities of 90 days or less when purchased. Restricted cash represents the funds held in reserve for a trust on behalf of Boston Edison to pay the principal and interest on the transition property securitization.

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 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 Sheets include $127.4 million and $150.6 million in Deferred credits - Payable to Affiliates as of December 31, 2005 and 2004, respectively. This amount is composed of payments received from affiliates as a result of the Company’s role as the sponsor of the NSTAR Pension Plan. In addition, Boston Edison's goodwill amortization expense allocation payable to its affiliated companies, ComElectric, Cambridge Electric and NSTAR Gas was $42.5 million as of December 31, 2004 and was included in Deferred credits - Other. There was no similar affiliated company payable amount as of December 31, 2005 as a result of Boston Edison reallocating a portion of the previously recorded goodwill from three other NSTAR subsidiary companies as of September 30, 2005. Refer to Note C for further information.

Additionally, the accompanying Consolidated Balance Sheets as of December 31, 2005 include a net allocation of affiliated companies' expenses of $21.6 million. Operational expenses are charged between Boston Edison and its affiliated companies on a cost sharing method based on proportionate use. As of December 31, 2004, a net receivable is due Boston Edison related to allocation of costs to affiliated companies.

11. Costs to Achieve (CTA)

CTA represent costs incurred to execute the merger that created NSTAR and includes the costs of a voluntary severance program, costs of financial advisors, legal costs and other transaction and systems integration costs. The original CTA estimate was $111 million of which approximately $72 million was allocated to Boston Edison. CTA was being amortized over 10 years at an annual rate of $7.2 million through the completion of the four-year rate freeze period based on the original rate plan and was estimated at $111 million as approved by the MDTE. Effective upon completion of the four-year rate freeze on August 25, 2003, the amortization expense was increased to reflect the actual CTA expenditures incurred. As a result, the total CTA amortization expense for 2005 and 2004 was approximately $10.7 million and reflect the actual CTA of approximately $143 million, of which approximately $93 million was allocated to Boston Edison.

12. Other Income (deductions), net

Major components of other income, net were as follows:

		Years ended December 31,
(in thousands)		2005		2004			2003
Equity earnings	$	1,044	$	1,131		$	1,567
Interest income		1,576		1,271			111
Rental income		1,620		1,537			1,393
Miscellaneous other income (includes
applicable income tax (expense))		86		(803	)		(697	)
	$	4,326 =====	$	3,136 =====		$	2,374 =====

Major components of other deductions, net were as follows:

		Years ended December 31,
(in thousands)		2005			2004			2003
Charitable contributions	$	(1,270	)	$	(1,266	)	$	(653	)
Property taxes		(24	)		(96	)		(120	)
Miscellaneous other deductions, (includes
applicable income tax benefit (expense))		65			497			(28	)
		(1,229	)		(865	)		(801	)
Total other income, net	$	3,097 ======		$	2,271 ======		$	1,573 =====

13. New Accounting Standards

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

During 2004, Boston Edison was subject to an agreement whereby all of its energy supply resource entitlements under long-term contracts 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. This transaction had been recorded as a net purchase of electricity. This agreement expired in December 2004 and most of Boston Edison's remaining long-term contracts were bought-out of in February 2005. Refer to Note L, "Contracts for the Purchase of Energy" for more detail on the buy-out of purchase power contracts.

During 2005, as part of its normal business operations, Boston Edison entered into transactions to sell energy from all of its remaining long-term energy supply resources to ISO-NE. Boston Edison records the net effect of transactions with the ISO-NE as an adjustment to purchased power expense.

Note B. Asset Retirement Obligations

Boston Edison adopted FIN 47 at December 31, 2005, as required. The recognition of an ARO has no impact on Boston Edison's earnings. In accordance with SFAS 71, Boston Edison established a regulatory asset to recognize future recoveries through depreciation rates for the recorded ARO. Boston Edison has identified several plant assets in which this condition exists and is related to plant assets containing asbestos materials. As a result, in December 2005, Boston Edison recognized an asset retirement cost of $0.4 million as an increase in utility property, an asset retirement liability of $8.5 million and a regulatory asset of $8.1 million.

For comparative purposes, the pro forma ARO that would have been recognized in accordance with FIN 47 as of December 31, 2004 and January 1, 2004 would have amounted to $8 million and $7.6 million, respectively.

For Boston Edison, the ultimate cost to remove utility plant from service (cost of removal) is recognized as a component of depreciation expense in accordance with approved regulatory treatment. As of December 31, 2005 and 2004, the estimated amount of the future cost of removal included in regulatory liabilities was approximately $150 million and $155 million, respectively, based on the estimated cost of removal component in current depreciation rates.

Note C. Non-Cash Regulatory Asset and Capital Transfer

As of September 30, 2005, NSTAR, Boston Edison's parent company, changed the classification of its Goodwill to a Regulatory asset. This change was adopted to better align with Boston Edison's existing rate recovery mechanism that allows for the recovery of goodwill from its customers over 40 years. As a result of this change, NSTAR has reallocated a portion of the previously recorded goodwill from three other subsidiary companies: ComElectric, Cambridge Electric and NSTAR Gas to Boston Edison. This change was effective as of September 30, 2005 and was accounted for as a non-cash capital transfer to Boston Edison of $319 million from NSTAR. This transfer represents Boston Edison's proportionate share of goodwill that arose from the merger that created NSTAR in accordance with the 1999 Rate Order from the MDTE approving the merger.

In addition to this transfer of goodwill and its classification to a regulatory asset and in accordance with the requirements of SFAS 109, “Accounting for Income Taxes,” Boston Edison recognized $174.6 million of accumulated deferred income taxes related to this goodwill along with a corresponding regulatory asset as of September 30, 2005. The regulatory asset, representing the accumulated deferred income taxes, will be amortized over the remaining life of the regulatory asset - goodwill (amounting to approximately $5.1 million annually) in accordance with NSTAR's merger rate order allowing recovery of goodwill. This additional amortization expense will be entirely offset by a corresponding deferred income tax expense - credit.

Note D. Regulatory Assets

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

Regulatory assets consisted of the following:

	December 31,
(in thousands)		2005		2004
Power contracts (including Yankee units)	$	607,222	$	916,754
Goodwill (Note C)		441,892		-
Retiree benefit costs		4,639		12,873
Generation-related costs		547,043		391,063
Merger costs to achieve		39,227		49,925
Income taxes, net		55,037		56,795
Purchased power costs		8,085		-
Redemption premiums		14,896		16,785
Other		37,050		821
Total current and long-term regulatory assets	$	1,755,091 =======	$	1,445,016 =======

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

Power contracts

The unamortized balance of the estimated costs to decommission the Connecticut Yankee (CY) and Yankee Atomic (YA) nuclear power plants was $63.1 million and $71.2 million at December 31, 2005 and 2004. Boston Edison’s liability for CY decommissioning and its recovery ends in 2010 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. Boston Edison does not earn a return on decommissioning costs, but a return is included in rates charged to Boston Edison by the plant operators. Refer to Note M, “Commitments and Contingencies” for more discussion.

In addition, at December 31, 2004, $234.8 million represents the recognition of one purchase power contract as a derivative and its above-market value and future recovery through Boston Edison’s transition charge. On March 1, 2005, Boston Edison closed on a securitization financing for $265.5 million to, in part, finance the buy-out of this one contract. Refer to Note E, “Derivative Instruments - Power Contracts” for further details. The remaining balance at December 31, 2005 and 2004 of $544.1 million and $610.8 million, respectively, represents the recognition of four purchase power contract buy-out agreements that Boston Edison executed in 2004 and their future recovery through Boston Edison’s transition charge. Refer to Note L, "Contracts for the Purchase of Energy" for further details.

For the power contracts that were terminated, Boston Edison does not earn a return on this regulatory asset. Boston Edison recognized this regulatory asset as a result of recognizing the contract termination liability in accordance with SFAS 146 "Accounting for Costs Associated with the Exit or Disposal Activities." As a result, Boston Edison has not treated this regulatory asset as an investment in which it would be entitled to earn a return. Furthermore, no cash outlay has been incurred by Boston Edison to create the regulatory asset. The contracts' termination payments will occur over time and will be collected from customers through Boston Edison's transition charge over the same time period. The cost recovery of these terminated contracts is through September 2016.

Allocated retiree benefit costs

The retiree benefit regulatory asset at December 31, 2005 of $4.6 million is comprised of carrying charges that will be recovered from customers commencing in 2006 related to its qualified pension and other postretirement benefit obligations. Under a 2003 MDTE order, there are pension and PBOP expenses deferred through 2005 that are amortized and collected from customers over three years. Boston Edison is allowed to recover its qualified pension and PBOP expenses through a reconciling rate mechanism. This reconciling rate 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.

Generation-related costs

Costs related to purchase power contract buy-outs and the divestiture of Boston Edison’s generation business are recovered with a return through the transition charge. This recovery occurs through 2019 for Boston Edison and is subject to adjustment by the MDTE.

As of December 31, 2005 and 2004, $526.1 million and $357.2 million, respectively, of these generation-related regulatory assets are collateralized with the Transition Property Securitization Certificates held by Boston Edison’s subsidiaries, BEC Funding, LLC and BEC Funding II, LLC. The certificates are non-recourse to Boston Edison.

Merger costs to achieve

An integral part of the merger that created NSTAR was the MDTE-approved rate plan of the retail utility subsidiaries of NSTAR. These costs are collected from Boston Edison’s distribution customers and exclude a return component. The amortization amount of these costs has been adjusted since the original recovery began to reflect the actual costs incurred. Refer to Note A to these Consolidated Financial Statements for more information on merger costs to achieve.

Income taxes, net

Approximately $64.8 million of this regulatory asset balance reflects deferred tax reserve deficiencies that the MDTE has allowed recovery of from ratepayers in accordance with an MDTE-approved settlement agreement. Offsetting these amounts is approximately $9.7 million of a regulatory liability associated with unamortized investment tax credits.

Purchased power costs

The purchased power costs at December 31, 2005 relate to electric basic service costs. Prior to March 1, 2005, customers had the option of continuing to buy electricity from Boston Edison at standard offer prices. Since 1998, Boston Edison has been allowed to defer the difference between the standard offer and basic service revenues and the cost to supply the power, plus carrying costs. As of March 1, 2005, basic service is the electricity that is supplied by the local distribution company when a customer has not chosen to receive service from a competitive supplier. The market price for basic service may fluctuate based on the average market price for power. Amounts collected through basic service are recovered on a fully reconciling basis.

Redemption premiums

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

Other

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

Note E. Derivative Instruments - Power Contracts

The electric distribution industry may contract to buy and sell electricity under option contracts, which allow the distribution company the flexibility to determine when and in what quantity to take electricity in order to align with its demand for electricity. These contracts would normally meet the definition of a derivative instrument requiring mark-to-market accounting. However, because electricity cannot be stored and utilities are obligated to maintain sufficient capacity to meet the electricity needs of its customer base, an option contract for the purchase of electricity typically qualifies for the normal purchases and sales exception as described in the FASB Statement of Financial Accounting Standard (SFAS) No. 133,“Accounting for Derivative Instruments and Hedging Activities” and Derivative Implementation Group (DIG) interpretations and, therefore, does not require mark-to-market accounting. Boston Edison accounts for its energy contracts in accordance with SFAS No. 133 and SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities."

Boston Edison has long-term purchase power agreements that are used primarily to meet its customer obligations. The majority of these agreements are not reflected as an asset or liability on the accompanying Consolidated Balance Sheets as they qualify for the normal purchases and sales exception. However, based on SFAS 133 and DIG interpretations, Boston Edison, as of December 31, 2004, had one remaining contract that was recorded at fair value on the accompanying Consolidated Balance Sheets. On March 1, 2005, Boston Edison closed on a securitization financing for $265.5 million to, in part, finance the buy-out of this one remaining contract that was classified as a derivative instrument at December 31, 2004. This one contract had a fair value of approximately $234.8 million at December 31, 2004 and was therefore removed as a derivative instrument from Deferred credits - Power contracts, along with the offsetting regulatory asset, on the accompanying Consolidated Balance Sheets. The securitization debt obligation was recorded along with an offsetting regulatory asset to reflect the future recovery of the debt obligation through Boston Edison's transition charge. At December 31, 2005, Boston Edison does not have any contracts that continue to be classified as derivative instruments. Refer to the accompanying Consolidated Financial Statements, Note L, for more detail on the buy-out of certain purchase power contracts.

Note F. Variable Interest Entities

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

Boston Edison has two wholly owned special purpose subsidiaries, BEC Funding LLC., established in 1999 and BEC Funding II, LLC established in 2004, to undertake the sale of $725 million and $265.5 million, respectively, in notes to a special purpose trust created by two Massachusetts state agencies. Boston Edison consolidates each of these entities. As part of Boston Edison's assessment of FIN 46R and, for compliance at December 31, 2003 or 2004, Boston Edison reviewed the substance of these entities to determine if it is still proper to consolidate these entities. Based on its review, Boston Edison has concluded that BEC Funding LLC and BEC Funding II, LLC are VIEs and should continue to be consolidated by Boston Edison.

For the March 31, 2004 effective date of FIN 46R, Boston Edison evaluated other entities with which it conducts significant transactions, including companies that supply power to Boston Edison through its purchase power agreements. Boston Edison determined that it is possible that two of these companies may be considered VIEs. In order to determine if these counterparties are VIEs and if Boston Edison is the primary beneficiary of these counterparties, Boston Edison concluded that it needed more information from the entities. Boston Edison attempted to obtain the information required and requested, in writing, these entities provide the Company with the necessary information. However, each of the entities has indicated that they will not provide the requested information as they are not contractually obligated to provide such confidential information. Since Boston Edison was unable to obtain the necessary information and, as allowed under a scope exception in FIN 46R, the accompanying Consolidated Financial Statements do not reflect the consolidation of any entities with which Boston Edison has a purchase power agreement.

Subsequent to the March 31, 2004 effective date, Boston Edison executed purchase power buy-out or restructuring agreements with a majority of the entities from which Boston Edison attempted to obtain additional information in order to determine if these entities are VIEs. These buy-out or restructuring agreements received regulatory approval in January 2005. Refer to Consolidated Financial Statements, Note L, for more detail on the purchase power buy-out agreements. The remaining potential entities that may be considered VIEs are associated with power plants with minimal MW capacity and would not have a material effect on Boston Edison's financial position. As a result, Boston Edison will no longer pursue obtaining the necessary information to determine whether it has a potential variable interest in these entities.

Note G. Income Taxes

Income taxes are accounted for in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS 109). SFAS 109 requires the recognition of deferred tax assets and liabilities for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 71 and SFAS 109, net regulatory assets of $55 million and $56.8 million and corresponding net increases in accumulated deferred income taxes were recorded as of December 31, 2005 and 2004, 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)		2005		2004
Deferred tax liabilities:
Plant-related	$	391,102	$	395,501
Regulatory asset - goodwill		173,332		-
Power contracts		99,108		-
Transition costs		123,149		151,015
Other		173,741		162,449
		960,432		708,965

Deferred tax assets:
Investment tax credits		9,728		10,402
Other		40,514		33,757
		50,242		44,159
Net accumulated deferred income taxes		910,190		664,806
Accumulated unamortized investment tax credits		15,073		16,117
	$	925,263 ======	$	680,923 ======

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

For Federal income tax purposes, Boston Edison files its return as part of the NSTAR consolidated income tax return. As such, the amount of current and deferred Federal income tax expense or benefit is calculated based on Boston Edison's stand alone taxable income and reflects the impact of both temporary and permanent book to tax differences. Therefore, Boston Edison is obligated to pay or receive from NSTAR its share of current Federal tax expense or benefit. Boston Edison's deferred Federal income tax liability represents future income tax payments to NSTAR.

The deferred income tax component by jurisdiction is follows:

(in thousands)		2005		2004
Deferred Federal tax liability and unamortized investment tax credits	$	807,861	$	600,188
Deferred state tax liability		117,402		80,735
Total deferred tax liability	$	925,263 =======	$	680,923 =======

Components of income tax expense were as follows:

		2005			2004			2003
Current income tax expense	$	16,023		$	43,314		$	42,977
Deferred income tax expense		68,599			46,261			48,024
Investment tax credit amortization		(1,044	)		(1,044	)		(1,044	)
Income taxes charged to operations		83,578			88,531			89,957
Tax expense on other income, net		1,999			1,466			1,015
Total income tax expense	$	85,577 ======		$	89,997 ======		$	90,972 =====

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:

	2005		2004		2003
Statutory tax rate	35.0	%	35.0	%	35.0	%
State income tax, net of federal income tax benefit	4.2		4.3		4.4
Investment tax credits	(0.5	)	(0.5	)	(0.5	)
Other	0.8		1.4		2.1
Effective tax rate	39.5 =====	%	40.2 =====	%	41.0 ====	%

Note H. Pension and Other Postretirement Benefits

1. Pension

Boston Edison is the sponsor of the NSTAR Pension Plan (the Plan), which is a defined benefit funded retirement plan that covers substantially all employees of NSTAR Electric & Gas.

In addition, NSTAR maintains non-qualified retirement plans for certain management employees of NSTAR Electric & Gas. Boston Edison was allocated approximately $2.6 million and $2.1 million in 2005 and 2004, respectively, of the net non-qualified retirement plan costs.

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

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

		December 31,
(in thousands)		2005			2004
Change in benefit obligation:
Benefit obligation, beginning of the year	$	1,022,983		$	926,712
Service cost		20,270			18,805
Interest cost		55,432			58,042
Plan participants’ contributions		42			61
Actuarial (gain) loss		(28,770	)		88,227
Settlement payments		(23,726	)		(18,588	)
Benefits paid		(51,269	)		(50,276	)
Benefit obligation, end of the year	$	994,962 =======		$	1,022,983 =======

Change in Plan assets:
Fair value of Plan assets, beginning of the year	$	894,754		$	829,126
Actual gain on Plan assets, net		69,812			94,431
Employer contribution		75,000			40,000
Plan participants’ contributions		42			61
Settlement payments		(23,726	)		(18,588	)
Benefits paid		(51,269	)		(50,276	)
Fair value of Plan assets, end of the year	$	964,613 =======		$	894,754 =======

The market-related value of the Plan's pension assets is determined based on the actual fair value as of the balance sheet date for all classes of assets. Therefore, the difference between the actual and expected return on Plan assets is reflected as a component of unrecognized actuarial net loss.

The Plan’s funded status was as follows:

		December 31,
(in thousands)		2005			2004
Funded status	$	(30,349	)	$	(128,229	)
Unrecognized actuarial net loss		383,037			432,584
Unrecognized prior service cost		(5,799	)		(6,609	)
Net amount recognized	$	346,889 =======		$	297,746 ======

Amounts recognized in the accompanying Consolidated Balance Sheets consisted of prepaid pension of $346,889,000 and $297,746,000 at December 31, 2005 and 2004, respectively.

The accumulated benefit obligations for the qualified pension plan as of December 31, 2005 and 2004 were $880,819,000 and $870,730,000, respectively.

Weighted average assumptions were as follows:

	2005		2004		2003
Discount rate at the end of the year	5.75	%	5.75	%	6.25	%
Expected return on Plan assets for the year (net of
expenses)	8.4	%	8.4	%	8.4	%
Rate of compensation increase at the end of the year	4.0	%	4.0	%	4.0	%

The Plan's discount rate is based on a rate modeling of a bond portfolio which approximates the Plan liabilities. In addition, management considers rates of high quality corporate bonds of appropriate maturities as published by nationally recognized rating agencies consistent with the duration of the Plan and through periodic bond portfolio matching. The Plan’s long-term rate of return is based on past performance and economic forecasts for the types of investments held in the Plan as well as the target allocation of the investments over a 20-year time period. This rate is presented net of both administrative expenses and investment expenses, which have averaged approximately 0.6% for 2005 and 2004.

Components of net periodic benefit cost were as follows:

		Years ended December 31,
(in thousands)		2005			2004			2003
Service cost	$	20,270		$	18,805		$	17,615
Interest cost		55,432			58,042			56,727
Expected return on Plan assets		(74,390	)		(70,794	)		(58,917	)
Amortization of prior service cost		(810	)		(810	)		(810	)
Amortization of transition obligation		-			379			601
Recognized actuarial loss		25,355			26,414			32,017
Net periodic benefit cost before allocation to affiliates	$	25,857 ======		$	32,036 ======		$	47,233 ======

The Company, as a sponsor of the Plan, allocated net costs and was reimbursed by its affiliated companies a total of $10.4 million, $14.1 million and $20.7 million in 2005, 2004 and 2003, respectively. The Company's discount rate used to calculate its net periodic benefit costs for 2005, 2004 and 2003 were 5.75%, 6.25% and 6.5%, respectively.

Certain postretirement health care benefits are eligible to certain active NSTAR Electric & Gas employees and certain retired non-union employees in conjunction with the Group Welfare Benefit Plan for Retirees of NSTAR. 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 following indicates the weighted average asset allocation percentage of the fair value of total Plan assets for each major type of Plan asset as of December 31^st as well as the Plan’s target percentages and the permissible range:


	Plan Assets		Target	Permissible
	2005	2004	Percentages	Ranges	Benchmark
Asset Category
Equity securities	51%	54%	50%	45% - 55%	Russell 300 Index
Debt securities	28%	26%	25%	20% - 30%	Lehman Aggregate
Real Estate	7%	5%	10%	5% - 15%	Wilshire NAREIT Index
Other	14%	15%	15%	5% - 15%
Total	100% ====	100% ====	100% ====

Other asset category primarily consists of hedge funds and market neutral securities.

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

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

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

As a result of the significant contributions made in 2005, Boston Edison does not anticipate making any contributions to the Plan in 2006.

The estimated benefit payments for the years after 2005 are as follows:

(in thousands)
2006	$	58,447
2007		61,380
2008		62,389
2009		68,274
2010		69,735
2011 - 2015		394,457
Total	$	714,682 =======

2. Other Postretirement Benefits

Boston Edison supports a portion of NSTAR's Group Welfare Benefits Plan for Retirees of NSTAR. The Plan provides health care and other benefits to retired employees who meet certain age and years of service eligibility requirements. These benefits include health and life insurance coverage and until April 1, 2003 included reimbursement of certain Medicare premiums for certain retirees. Under certain circumstances, eligible retirees are required to contribute 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 Boston Edison was $15.6 million, $15.5 million and $22.1 million in 2005, 2004 and 2003, respectively.

3. Savings 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 eligible base and cash compensation) included in the accompanying Consolidated Statements of Income amounted to approximately $5 million in 2005, 2004 and 2003. The plan was amended to allow for increased maximum annual pre-tax contributions and additional “catch-up” pre-tax contributions for participants age 50 or older, acceptance of other types of “roll-over” pre-tax funds from other plans and the option of reinvesting dividends paid on the NSTAR Common Share Fund or receiving such dividends in cash. The election to reinvest dividends paid on the NSTAR Common Share Fund or receive the dividends in cash is subject to a freeze period beginning seven days prior to the date any dividend is paid. During this period, participants cannot change their election. Dividends are paid to this plan four times a year in February, May, August and November.

Note I. Capital Stock

Cumulative Preferred Stock

Non-mandatory redeemable series:

Par value $100 per share, 2,890,000 shares authorized and 430,000 shares issued and outstanding:

(in thousands, except per share amounts)

	Current Shares	Redemption	December 31,
Series	Outstanding	Price/Share	2005	2004
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 =====

Boston Edison has two outstanding series of non-mandatory redeemable preferred stock. Both series are part of a class of Boston Edison's Cumulative Preferred Stock. Upon any liquidation of Boston Edison, holders of the Cumulative Preferred stock are entitled to receive the liquidation preference for their shares before any distribution to the holder of the common stock. The liquidation preference for each outstanding series of Cumulative Preferred Stock is equal to the par value ($100.00 per share), plus accrued and unpaid dividends.

Note J. Indebtedness

1. Long-Term Debt

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

		December 31,
(in thousands)		2005			2004
Debentures:
Floating rate (4.1% in 2005 and 2.57% in 2004), due October 2005	$	-		$	100,000
7.80%, due May 2010		125,000			125,000
4.875%, due April 2014		300,000			300,000
4.875%, due October 2012		400,000			400,000
Sewage facility revenue bonds, due through 2015		14,902			16,591
Massachusetts Industrial Finance Agency (MIFA)
bonds 5.75%, due February 2014		15,000			15,000
Transition Property Securitization Certificates:
6.62%, due March 2005		-			7,296
6.91%, due September 2007		108,923			170,876
7.03%, due March 2010		171,624			171,624
3.40%, due September 2006		15,066			-
3.78%, due September 2008		60,978			-
4.13%, due September 2011		104,619			-
4.40%, due September 2013		56,906			-
		1,373,018			1,306,387
Unamortized debt discount		(3,836	)		(4,357	)
Amounts due within one year		(63,380	)		(141,735	)
Total long-term debt	$	1,305,802 =======		$	1,160,295 =======

On October 17, 2005, Boston Edison redeemed the entire outstanding balance of $100 million aggregate principal amount of its Floating Rate Debentures due on that date.

On April 16, 2004, Boston Edison issued $300 million of ten-year fixed rate (4.875%) Debentures. The net proceeds were used to repay outstanding short-term debt balances incurred, in part, to pay the redemption price of the 7.80% Debentures. The premium paid to redeem the 7.80% Debentures will be amortized over ten years, the term of the new 4.875% Debentures.

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 2005 and 2004. The interest rate of the bonds was 7.375% for both 2005 and 2004. 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 were redeemable beginning in February 2004 at a redemption price of 102%. The redemption price decreased to 101% in February 2005 and to par in February 2006.

The Transition Property Securitization Certificates held by Boston Edison's subsidiaries, BEC Funding LLC and BEC Funding II, LLC, are each collateralized with separate securitized regulatory assets with combined balances of $526.1 million and $357.2 million as of December 31, 2005 and 2004, respectively. BEC Funding II, LLC was established to facilitate the sale on March 1, 2005 of $265.5 million of electric rate reduction certificates at a public offering. Boston Edison, as servicing agent for BEC Funding, LLC and BEC Funding II, LLC collected $129.2 million and $96 million in 2005 and 2004, respectively. These Certificates are non-recourse to Boston Edison.

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 2005 are approximately $63.4 million in 2006, $102.4 million in 2007, $103.5 million in 2008, $103.3 million in 2009, $194.5 million in 2010 and $805.9 million thereafter.

2. Source of Additional Capital, Financial Covenant Requirements and Lines of Credit

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

As of December 31, 2005, Boston Edison has $200 million available under its current shelf registration, as approved by the SEC. On April 1, 2004, the MDTE approved the issuance by Boston Edison of up to $500 million of debt securities from time to time on or before December 31, 2005. On April 16, 2004, Boston Edison sold $300 million of ten-year fixed rate (4.875%) Debentures under this shelf registration. The net proceeds were primarily used to repay outstanding short-term debt balances. On December 29, 2005, the MDTE approved Boston Edison's request to extend the term of its financing plan until June 30, 2006 for the remaining $200 million in securities that have yet to be issued.

Boston Edison has approval from the FERC to issue short-term debt securities from time to time on or before December 31, 2006, with maturity dates no later than December 31, 2007, in amounts such that the aggregate principal does not exceed $450 million at any one time. Boston Edison has a five-year, $350 million revolving credit agreement that expires in November 2009. However, unless Boston Edison receives necessary approvals from the MDTE, the credit agreement will expire 364 days from the date of the first draw under the agreement. At December 31, 2005 and 2004, there were no amounts outstanding under the revolving credit agreement. This credit facility serves as backup to Boston Edison's $350 million commercial paper program that had a $197 million and $46.5 million balance at December 31, 2005 and 2004, respectively. Under the terms of the revolving credit agreement, Boston Edison is required to maintain a consolidated maximum total debt to capitalization ratio of not greater than 65% at all times, excluding Transition Property Securitization Certificates, and excluding accumulated other comprehensive income (loss) from common equity. At December 31, 2005 and 2004, Boston Edison was in full compliance with its covenants in connection with its short-term credit facilities as the ratios were 45.9% and 53.1%, respectively.

The weighted average short-term interest rates including fees were 3.72% and 1.49% in 2005 and 2004, respectively. In aggregate, short-term borrowings totaled $197 million and $46.5 million at December 31, 2005 and 2004, respectively.

Note K. 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 $10.1 million and $6.5 million for 2005 and 2004, 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, 2005 and 2004 were as follows:

	2005		2004
	Carrying	Fair		Carrying	Fair
(in thousands)	Amount	Value		Amount	Value
Long-term indebtedness	$1,369,182	$1,379,350		$1,302,030	$1,373,170
(including current maturities)

Note L. Contracts for the Purchase of Energy

As a Massachusetts distribution company, Boston Edison is required to obtain and resell power to retail customers for those who choose not to buy energy from a competitive energy supplier. Standard offer service option for customers ended on February 28, 2005. Therefore, all customers who had not chosen to receive service from a competitive supplier were provided default service, which was designated basic service thereafter. Basic service rates are reset every six months (every three months for large commercial and industrial customers). The price of basic service is intended to reflect the average competitive market price for power. For basic service power supply, Boston Edison makes periodic market solicitations consistent with MDTE regulations. During 2005, Boston Edison entered into short-term power purchase agreements to meet its entire basic service supply obligation, other than to its largest customers, for the period January 1, 2006 through June 30, 2006 and for 50% of its obligation, other than to these large customers, for the second-half of 2006. Boston Edison has entered into short-term power purchase agreements to meet its entire basic service supply obligation for large customers through June 2006. A request for proposals will be issued quarterly in 2006 for the remainder of the obligation for large customers and semi-annually for non-large customers. For 2005, Boston Edison entered into agreements ranging in length from three to twelve-months.

In 2004, Boston Edison executed agreements to buy-out or restructure five of its purchase power agreements that required MDTE approval. These agreements constituted approximately 460 MW of the remaining 780 MW of capacity, and reduced the amount of above-market costs that Boston Edison will collect from its customers through its transition charges. As of December 31, 2004, two of these agreements received MDTE approval and were recognized. These two agreements require Boston Edison to make monthly payments through September 2011 totaling approximately $125 million. These buy-out/restructuring agreements provide no economic benefit to Boston Edison and, therefore, the agreements' contract termination costs were recorded on the accompanying Consolidated Financial Statements when completed.

On January 7, 2005, Boston Edison received approval from the MDTE for an additional two agreements that were anticipated to be completed by February 2005. These two agreements were binding as of December 31, 2004 but were contingent upon regulatory approval. Since the contingency was removed during February 2005, Boston Edison recorded the contract termination cost as of December 31, 2004. One of the two agreements requires Boston Edison to make net monthly payments through September 2011 totaling approximately $416 million. The other agreement requires Boston Edison to make net monthly payments through September 2016 totaling approximately $215 million. Boston Edison anticipates making these cash payments from funds generated from operations and will be fully recovered through Boston Edison's transition charge.

The total amount recognized as of December 31, 2005 and 2004 for obligations relating to four of the five contracts is approximately $544.1 million and $610.8 million; approximately $114.3 million and $104.9 million are reflected as a component of Current liabilities - power contracts and approximately $429.8 million and $505.9 million as a component of Deferred credits - power contracts on the accompanying Consolidated Balance Sheets as of December 31, 2005 and 2004, respectively. Boston Edison has recorded a corresponding regulatory asset to reflect the full future recovery of these payments through its transition charge. This recognition represents a non-cash increase to assets and liabilities.

Also in January 2005, the MDTE approved the one remaining contract buy-out with a supplier that reduced the overall amount of transition costs to be paid for above-market contracts. This contract is a buy-out arrangement whereby Boston Edison has made a contract termination payment in full release of its obligation under the purchase power agreement. On August 31, 2004, Boston Edison filed with the MDTE a proposed financing plan that sought approval for full recovery of this buy-out cost and the issuance of $265.5 million of transition property securitization bonds to provide the funds for this buy-out agreement. The MDTE approved the financing plan in January 2005. On February 15, 2005, the bonds were priced at a weighted average yield of 4.15% and the securitization financing closed on March 1, 2005.

Note M. Commitments and Contingencies

1. Service Quality Indicators

On March 1, 2005, Boston Edison filed its 2004 Service Quality Report with the MDTE that demonstrated the Company achieved sufficient levels of reliability and performance; the reports indicate that no penalty was assessable for 2004. On December 30, 2005, the MDTE issued a formal approval of this filing.

2. 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 2005 are as follows:


(in thousands)
2006	$	11,392
2007		9,776
2008		9,018
2009		8,577
2010		7,342
Years thereafter		21,321
	$	67,426 ======

The total expense for both lease and transmission agreements was $15.8 million in 2005, $15.3 million in 2004 and $13.7 million in 2003, net of capitalized expenses of $1.3 million in 2005, $1.2 million in 2004 and $1.6 million in 2003.

Transmission

As a member of ISO-NE, Boston Edison is subject to the terms and conditions of the ISO-NE tariff through February 2010. This obligates Boston Edison to pay for regional network services through that period to support the pooled transmission facilities requirements of other New England transmission owners whose facilities are used by Boston Edison. These payments amounted to $67.1 million, $53.2 million and $46.5 million in 2005, 2004 and 2003, respectively.

Power Supply

Boston Edison has entered into short-term power purchase agreements to meet its entire basic service supply obligation, other than to largest customers, for the period January 1, 2006 through June 30, 2006 and for 50% of its obligation, other than to these largest customers, for the second-half of 2006. Boston Edison has entered into a short-term power purchase agreement to meet its entire basic service supply obligation for large customers through June 2006. A request for proposals will be issued quarterly in 2006 for the remainder of the obligation for large customers and semi-annually for non-large customers in accordance with MDTE requirements. Boston Edison entered into agreements ranging in length from three to twelve-months effective January 1, 2005 through December 31, 2005 with suppliers to provide full basic service energy and ancillary service requirements at contract rates approved by the MDTE. Boston Edison is currently recovering payments it is making to suppliers from its customers and has financial and performance assurances and financial guarantees in place with those suppliers to protect 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 receives 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 L, “Contracts for the Purchase of Energy” for a further discussion.

The following represents Boston Edison's long-term energy related contractual commitments:

(in millions)		2006		2007		2008		2009		2010	Years Thereafter		Total
Electric capacity obligations	$	2	$	2	$	2	$	2	$	3	$ 21	$	32
Purchase power buy- out obligations		114		119		120		120		117	62		652
	$	116 ===	$	121 ===	$	122 ===	$	122 ===	$	120 ===	$ 83 ===	$	684 ===

Electric capacity obligations represent remaining capacity costs of long-term contracts that reflect Boston Edison's proportionate share of capital and fixed operating costs of certain generating units. In 2005, these costs were attributed to 185 MW of capacity purchased. Energy costs are paid to generators based on a price per kWh actually received into Boston Edison's distribution system and are included in the total cost. Total capacity purchased in 2005 was 548 MW. These contracts expire at various times through 2019.

Purchase power buy-out obligations represent the buy-out/restructuring agreements for contract termination costs that reduce the amount of above-market costs that Boston Edison will collect from its customers through its transition charges. These agreements require Boston Edison to make net monthly payments through September 2016.

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, 2005, Boston Edison’s portion of these guarantees amounted to $6.7 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 2005, NEH repurchased a total of 110,000 of its outstanding shares from all equity holders and NHH repurchased a total of 650 outstanding shares from all equity holders. Through December 31, 2005, Boston Edison’s reduction of its equity ownership resulting from NEH buy-back of 12,156 shares and NHH buy-back of 72 shares was approximately $342,000.

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, 2005, the total remaining approximate cost for decommissioning and/or security or protection of each nuclear unit is as follows: $515.7 million for CY and $149.3 million for YA. Of these amounts, Boston Edison is obligated to pay $49 million towards the decommissioning of CY and $14.2 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 and cash flows. These estimates may be revised from time to time based on information available to the Yankee Companies regarding future costs. The Yankee Companies have received approval from FERC for recovery of these costs and Boston Edison expects any additional increases to these costs to be included in future rate applications with the FERC, with any resulting adjustments being charged to their respective sponsors, including Boston Edison. Boston Edison would recover its share of any allowed increases from customers through the transition charge.

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

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

CY is currently in litigation with Bechtel over the termination of its decommissioning contract. Additionally, Bechtel filed a complaint against CY asserting several claims including wrongful termination. Bechtel sought to garnish the decommissioning trust and related payments. In October 2004, Bechtel and CY entered into a stipulation under which Bechtel relinquished its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CY's real property in Connecticut with a book value of $7.9 million and the escrowing of portions of the sponsors' periodic payments, up to a total of $41.7 million, all of which the sponsors, which include Boston Edison, are scheduled to pay to CY through June 30, 2007. On January 27, 2006, the Connecticut Superior Court issued a finding that the real property and the periodic payments were subject to attachment and garnishment, respectively, which is likely to result in the implementation of the stipulated escrowing arrangement. CY may appeal the Superior Court finding. Discovery in the termination litigation is drawing to a close and a trial has been scheduled for May 2006.

During the course of carrying out the decommissioning work, YA has identified increases in the scope of soil remediation and certain other remediation required to meet environmental standards beyond the levels assumed in the 2003 Estimate. On November 23, 2005, YA submitted a filing to the FERC for revisions to its Rate Schedules to revise the level of collections to recover the costs of completing the decommissioning of YA's retired nuclear generating plant (the 2005 Estimate). The schedule for the completion of physical work will need to extend until the end of August 2006 and the costs of completing decommissioning will be approximately $63 million greater than the estimate that formed the basis of the 2003 FERC settlement. Based on this allocation increase, Boston Edison is obligated to pay $6 million to the decommissioning of YA. Most of the cost increase relates to decommissioning expenditures that will be made during 2006, followed by a significant reduction in those charges during the years 2007 through 2010. On January 31, 2006, FERC issued an order accepting the rates for filing, effective February 1, 2006, subject to hearing and refund. FERC ordered the hearing held in abeyance pending the outcome of settlement procedures.

3. Financial and Performance Guarantees

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

At December 31, 2005, outstanding guarantees totaled $20.8 million as follows:

(in thousands)
Letters of Credit	$	7,500
Surety Bonds		6,673
Other Guarantees		6,660
Total Guarantees	$	20,833 ======

Boston Edison has also issued $6.7 million of residual value guarantees related to its equity interest in the Hydro-Quebec transmission companies.

4. Environmental Matters

5. Regulatory and Legal Proceedings

a. Regulatory proceedings

On December 30, 2005, the MDTE approved a multi-year rate Settlement Agreement between the Attorney General of Massachusetts, NSTAR and several interveners, for adjustments to Boston Edison's transition and distribution rates effective January 1, 2006 and May 1, 2006, respectively. Effective with the January 1^st date adjustment, Boston Edison will freeze its total transition and distribution rates through 2012. Additionally, the Settlement Agreement establishes performance-based distribution rate increases (PBR) beginning January 1, 2007. The PBR will result in annual inflation-adjusted distribution rates increases that will be offset by a decrease in transition rates through 2012.

In December 2005, Boston Edison filed proposed transition rate adjustments for 2006, including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2005. The MDTE subsequently approved tariffs for each retail electric subsidiary effective January 1, 2006. The filings are to be updated in March 2006 to reflect final 2005 costs and revenues which are subject to final reconciliation. As part of the rate Settlement Agreement approved by the MDTE on December 30, 2005, transition rates are further impacted by a reduction of approximately $15 million effective January 1, 2006 and by approximately $23 million on May 1, 2006 and are deferred with carrying charges at a rate of 10.88%.

Settlement discussions for the reconciliation of Boston Edison's 2004 costs for transition, transmission, standard offer and basic service have been delayed and will be combined with the settlement of 2005 costs or decided by the MDTE in a future hearing. NSTAR Electric cannot predict the timing or the ultimate outcome of these settlement discussions or adjustments.

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

Item 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.

Item 9A. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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

Item 9B. Other Information

None

Table of Contents

Part IV

Item 15. Exhibits and Financial Statement Schedules

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

1.	Financial Statements:
		Page

Report of Independent Registered Public Accounting Firm		30

Consolidated Statements of Income for the years ended December 31,
2005, 2004 and 2003		31

Consolidated Statements of Retained Earnings for the years ended
December 31, 2005, 2004 and 2003		32

Consolidated Balance Sheets as of December 31, 2005 and 2004		33

Consolidated Statements of Cash Flows for the years ended
December 31, 2005, 2004 and 2003		34

Notes to Consolidated Financial Statements		35

2.	Financial Statement Schedule:

Schedule II - Valuation and Qualifying Accounts for the years ended
December 31, 2005, 2004 and 2003		63

3.	Exhibits:

Refer to the exhibits listing beginning below.

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

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

4.4		Boston Edison Company Revolving Credit Agreement dated November 15, 2002			4.4		1-2301 Form 10-Q for the quarter ended March 31, 2003

4.5		Registration Statement for $500 million in Boston Edison Debt Securities, dated December 23, 2003			-		Form S-3 Registration Statement, filed December 23, 2003 (Registration 333-111476)

4.6		Prospectus Supplement to Registration Statement for $300 million in Boston Edison Debt Securities, dated January 9, 2004			-		Rule 424(b)(5) Prospectus Supplement, filed April 14, 2004 (Registration 333-111476)

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

10.4		Amended and Restated Power Purchase Agreement (NEA A PPA), dated August 19, 2004, by and between Boston Edison and Northeast Energy Associates L.P.			10.18		1-4768 Form 10-K of NSTAR for the year ended December 31, 2005

10.5		Amended and Restated Power Purchase Agreement (NEA B PPA), dated August 19, 2004, by and between Boston Edison and Northeast Energy Associated L. P.			10.19		1-4768 Form 10-K of NSTAR for the year ended December 31, 2005

10.6		The Bellingham Execution Agreement, dated August 19, 2004 between Boston Edison and Northeast Energy Associates L. P.			10.22		1-4768 Form 10-K of NSTAR for the year ended December 31, 2005

10.7		Purchase and Sale Agreement, dated June 23, 2004, between Boston Edison and Transcanada Energy Ltd. (Ocean State Power Contract)			10.23		1-4768 Form 10-K of NSTAR for the year ended December 31, 2005

	Transmission Agreements

10.2.1		New England Power Pool Agreement (NEPOOL) dated September 1, 1971 as amended through August 1, 1977, between NEGEA Service Corporation, as agent for Boston Edison company and various other electric utilities operating in New England together with amendments dated August 15, 1978, January 31, 1979 and February 1, 1980. (Exhibit 5(c)13 to New England Gas and Electric Association's Form S-16 (April 1980), File No. 2-64731)		10.2.1		1-4768 Form 10-K of NSTAR for the year ended December 31, 2005

10.2.1.1			Second Restated NEPOOL Agreement among Boston Edison and various other electric utilities operating in New England, dated August 16, 2004		10.2.1.1		1-4768 Form 10-K of NSTAR for the year ended December 31, 2005

10.2.1.2			Transmission Operating Agreement among Boston Edison and various electric transmission providers in New England and ISO New England Inc., dated February 1, 2005		10.2.1.2		1-4768 Form 10-K of NSTAR for the year ended December 31, 2005

10.2.1.3			Market Participants Service Agreement among Boston Edison and various other electric utilities operating in New England, NEPOOL and ISO New England Inc., dated February 1, 2005		10.2.1.3		1-4768 Form 10-K of NSTAR for the year ended December 31, 2005

10.2.1.4			Rate Design and Funds Disbursement Agreement among Boston Edison and various other electric transmission providers in New England, dated February 1, 2005		10.2.1.4		1-4768 Form 10-K of NSTAR for the year ended December 31, 2005

Exhibit 12			Statement re Computation of Ratios
12.1			Computation of Ratio of Earnings to Fixed Charges for the Year ended December 31, 2005 (filed herewith)

12.2			Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements for the Year ended December 31, 2005 (filed herewith)

Exhibit 21			Subsidiaries of the Registrant		21.1.1		1-2301 Form 10-K for the year ended December 31, 2004

Exhibit 23			Consent of Independent Accountants
23.1			(filed herewith)

Exhibit 31		Rule 13a - 15/15d-15(e) Certifications
31.1		Certification Statement of Chief Executive Officer of Boston Edison pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith)

31.2		Certification Statement of Chief Financial Officer of Boston Edison pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith)
Exhibit 32		Section 1350 Certifications

32.1		Certification Statement of Chief Executive Officer of Boston Edison pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith)

32.2		Certification Statement of Chief Financial Officer of Boston Edison pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith)

Table of Contents

SCHEDULE II

BOSTON EDISON COMPANY

VALUATION AND QUALIFYING ACCOUNTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

(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, 2005	$	14,091	$	12,394	$	4,678	$	16,779	$	14,384
Year Ended December 31, 2004	$	15,692	$	12,278	$	3,827	$	17,706	$	14,091
Year Ended December 31, 2003	$	19,084	$	6,225	$	2,964	$	12,581	$	15,692

Table of Contents

FORM 10-K

BOSTON EDISON COMPANY

DECEMBER 31, 2005

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 7, 2006	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 7th day of March 2006.

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, 2005
	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 6, 2006
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

Net income from continuing operations	$	131,248
Income taxes		85,577
Fixed charges (including securitization certificates)		93,014
Total	$	309,839 =======

Interest expense	$	87,761
Interest component of rentals		5,253
Total	$	93,014 ======

Ratio of earnings to fixed charges		3.33 ======

Net income from continuing operations	$	131,248
Income taxes		85,577
Fixed charges (including securitization certificates)		93,014
Total	$	309,839 =======

Interest expense	$	87,761
Interest component of rentals		5,253
Subtotal		93,014
Preferred stock dividend requirements		3,238
Total	$	96,252 ======

Ratio of earnings to fixed charges		3.22 =====

I, Thomas J. May, certify that:

1.	I have reviewed this annual report on Form 10-K of Boston Edison Company;
2.	Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3.	Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of Boston Edison Company as of, and for, the periods presented in this annual report;
4.	Boston Edison Company's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for Boston Edison Company and we have:
	a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to Boston Edison Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
	b)	evaluated the effectiveness of Boston Edison Company’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report, based on such evaluation; and
	c)	disclosed in this annual report any change in Boston Edison Company’s internal control over financial reporting that occurred during the most recent fiscal year that has materially affected, or is reasonably likely to materially affect, Boston Edison Company’s internal control over financial reporting.
5.	Boston Edison Company's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to Boston Edison Company's auditors and the audit committee of NSTAR's board of trustees:
	a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect Boston Edison Company's ability to record, process, summarize and report financial information; and
	b)	any fraud, whether or not material, that involves management or other employees who have a significant role in Boston Edison Company's internal control over financial reporting.

I, James J. Judge, certify that:

1.	I have reviewed this annual report on Form 10-K of Boston Edison Company;
2.	Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3.	Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of Boston Edison Company as of, and for, the periods presented in this annual report;
4.	Boston Edison Company's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for Boston Edison Company and we have:
	a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to Boston Edison Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
	b)	evaluated the effectiveness of Boston Edison Company’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report, based on such evaluation; and
	c)	disclosed in this annual report any change in Boston Edison Company’s internal control over financial reporting that occurred during the most recent fiscal year that has materially affected, or is reasonably likely to materially affect, Boston Edison Company’s internal control over financial reporting.
5.	Boston Edison Company's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to Boston Edison Company's auditors and the audit committee of NSTAR's board of trustees:
	a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect Boston Edison Company's ability to record, process, summarize and report financial information; and
	b)	any fraud, whether or not material, that involves management or other employees who have a significant role in Boston Edison Company's internal control over financial reporting.


Date: March 7, 2006			By:	/s/ JAMES J. JUDGE James J. Judge Senior Vice President, Treasurer and Chief Financial Officer