Nstar 10-K 2005 FY Annual report

UNITED STATES SECURITIES AND

EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2005

or

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

For the transition period from                      to                     

Commission file number 1-14768

NSTAR

(Exact name of registrant as specified in its charter)

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

617 424-2000

(Registrant’s telephone number, including area code)

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

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

x  Yes    ¨  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

¨  Yes    x  No

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

x  Yes    ¨  No

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, as defined in Rule 12b-2 of the Exchange Act.

Large accelerated filer  x            Accelerated filer  ¨            Non-accelerated filer  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act)

¨  Yes    x  No

The aggregate market value of the 106,808,376 shares of voting stock of the registrant held by non-affiliates of the registrant, computed as the average of the high and low market prices of the common shares as reported on the New York Stock Exchange consolidated transaction reporting system for NSTAR Common Shares as of the last business day of the registrant’s most recently completed second fiscal quarter: $3,291,834,148.

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

Class	Outstanding at February 17, 2006
Common Shares, $1 par value	106,808,376 Shares

Documents Incorporated by Reference

Sections of NSTAR’s Definitive Proxy Statement for the 2006 Annual Meeting of Shareholders to be held on May 4, 2006 are incorporated by reference into Parts I and III of this Form 10-K.

NSTAR

Form 10-K Annual Report - December 31, 2005

		Page
	Part I
Item 1.	Business	2
Item 1A	Risk Factors	9
Item 1B.	Unresolved Staff Comments	11
Item 2.	Properties	11
Item 3.	Legal Proceedings	11
Item 4.	Submission of Matters to a Vote of Security Holders	12
Item 4A.	Executive Officers of the Registrant	12
	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	13
Item 6.	Selected Consolidated Financial Data	14
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 8.	Financial Statements and Supplementary Data	49
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	89
Item 9A.	Controls and Procedures	89
Item 9B.	Other Information	89
	Part III
Item 10.	Trustees and Executive Officers of the Registrant	90
Item 11.	Executive Compensation	90
Item 12.	Security Ownership of Certain Beneficial Owners and Management	90
Item 13.	Certain Relationships and Related Transactions	90
Item 14.	Principal Accountant Fees and Services	90
	Part IV
Item 15.	Exhibits and Financial Statement Schedules	91
Signatures		96

Important Shareholder Information

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

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Part I

Item 1. Business

(a) General Development of Business

NSTAR (or the Company) is a holding company engaged through its subsidiaries in the energy delivery business serving approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric distribution customers in 81 communities and approximately 300,000 natural gas distribution customers in 51 communities. NSTAR’s retail utility subsidiaries are Boston Edison Company (Boston Edison), Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas). Its wholesale electric subsidiary is Canal Electric Company (Canal). NSTAR’s three retail electric companies collectively operate as “NSTAR Electric.” Reference in this report to “NSTAR” shall mean the registrant NSTAR or NSTAR and its subsidiaries as the context requires. Reference in this report to “NSTAR Electric” shall mean Boston Edison, ComElectric and Cambridge Electric together. NSTAR’s non-utility, unregulated operations include district energy operations primarily through its Advanced Energy Systems, Inc. subsidiary, telecommunications operations (NSTAR Communications, Inc. (NSTAR Com)) and a liquefied natural gas service company (Hopkinton LNG Corp.). Utility operations accounted for approximately 96% of consolidated operating revenues in 2005, 2004 and 2003.

(b) Financial Information about Industry Segments

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

(c) Narrative Description of Business

Principal Products and Services

NSTAR Electric

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

NSTAR Electric’s operating revenues and energy sales percentages by customer class for the years 2005, 2004 and 2003 consisted of the following:

	Revenues ($)						Energy Sales (mWh)
	2005		2004		2003		2005		2004		2003
Retail:
Commercial	54	%	54	%	54	%	60	%	59	%	59	%
Residential	39	%	39	%	38	%	31	%	31	%	31	%
Industrial and other	6	%	6	%	7	%	8	%	9	%	9	%
Wholesale and contract sales	1	%	1	%	1	%	1	%	1	%	1	%

Electric Rates

Retail electric delivery rates are established by the Massachusetts Department of Telecommunications and Energy (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

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ongoing operating and maintenance costs), and a reconciling rate adjustment mechanism for recovery of costs associated with NSTAR’s obligation to provide its 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 NSTAR’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 NSTAR Electric had approximately 32%, 24% and 26%, 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 NSTAR Electric’s transition rates of $20 million from what would otherwise have been billed in 2006. Subsequently, any change in distribution rates will be offset by an equal and opposite change in the transition rates through 2012. This Settlement Agreement permits NSTAR Electric to increase its distribution rates by $30 million effective May 1, 2006, with a corresponding reduction in transition rates. For NSTAR Gas customers, the settlement includes an adjustment to the cost of gas adjustment clause to defer recovery of approximately $18.5 million beginning January 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, NSTAR Electric makes periodic market solicitations consistent with MDTE regulations. During 2005, NSTAR Electric 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. NSTAR Electric has entered into short-term power purchase agreements to meet its entire basic service supply obligation for large customers through March 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, NSTAR Electric entered into agreements ranging in length from three to twelve-months.

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

The December 30, 2005 Settlement Agreement approved by the MDTE requires NSTAR Electric to design a policy for the procurement of basic service supply for residential customers to take effect July 1, 2006, permitting NSTAR Electric to execute energy supply contacts for one, two and three-years procuring fifty,

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twenty-five and twenty-five percent, respectively, of its total energy load requirements. NSTAR Electric 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.

NSTAR Electric’s load for 2005 reached an all-time peak demand of 4,621 megawatts (MW) on July 27, 2005 which was 4.7% more than the previous level of 4,415 MW established in 2002 and 8.6% more than the 2004 peak demand of 4,254 MW.

Wholesale Market and Transmission Rule Changes

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 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. NSTAR Electric’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 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. 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, by March 6, 2006. NSTAR cannot predict the actual impact these changes will have on NSTAR Electric 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 NSTAR’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. Refer to the accompanying “Management’s Discussion and Analysis” for more detail on proceedings before the FERC.

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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 NSTAR Electric and the ISO-NE, as the operator of the New England transmission grid. Separate agreements govern the operation of the spot power and related markets, the ISO-NE’s interactions with market participants and merchant transmission facilities.

NSTAR Gas

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

NSTAR Gas’ operating revenues and energy sales percentages by customer class for the years 2005, 2004 and 2003, consisted of the following:

	Revenues ($)						Energy Sales (therms)
	2005		2004		2003		2005		2004		2003
Gas Sales and Transportation:
Residential	64	%	61	%	61	%	46	%	45	%	47	%
Commercial	23	%	25	%	25	%	32	%	33	%	33	%
Industrial and other	8	%	9	%	10	%	17	%	17	%	17	%
Off-System and contract sales	5	%	5	%	4	%	5	%	5	%	3	%

Gas Rates

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

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

On February 28, 2005, the MDTE approved a petition by NSTAR Gas to change a portion of its gas procurement practices. As approved, NSTAR Gas began purchasing financial contracts based upon NYMEX natural gas futures in order to ultimately lock in prices for approximately one-third of its projected normal winter gas requirements. NSTAR Gas will not take physical delivery of the gas when the financial contracts are executed. All costs incurred will continue to be included in the CGAC. Refer to the Consolidated Financial Statements,Note F, for more details.

Under the MDTE approved 2000 regulations, expanding the choice of gas suppliers to all customers and providing for a five-year transition period, a three-year review of market conditions was established to determine

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whether the supply market had become sufficiently competitive to warrant removal or modification of the LDC’s service obligation with respect to planning and procurement. The MDTE previously had approved the compliance process submitted by NSTAR Gas and other LDCs that implement the unbundling of retail gas services to all customers. Among the important provisions are: setting the LDC as the default service provider, certification of competitive suppliers/marketers, extension of the MDTE’s consumer protection rules to residential customers taking competitive service, requirement for LDCs to provide suppliers/marketers with customers usage data, and requirement for suppliers/marketers to disclose service terms to potential customers. The MDTE has also ruled on requiring the mandatory assignment of the LDC’s upstream pipeline and storage capacity and downstream peaking capacity to customers who elect a competitive gas supply. This eliminates potential stranded cost exposure for the LDCs for the five-year transition period. In January 2004, the MDTE opened a new docket to determine whether the upstream capacity market is sufficiently competitive to warrant the voluntary assignment of interstate pipeline capacity to other entities. On June 6, 2005, the MDTE ruled that mandatory capacity assignment based upon “slice of system”, or the proportionate share of all upstream capacity resources, should continue.

Gas Supply, Transportation and Storage

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

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

In addition to the firm transportation and gas supplies mentioned above, NSTAR Gas utilizes contracts for underground storage and liquefied natural gas (LNG) facilities to meet its winter peaking demands. The LNG facilities, described below, are located within NSTAR Gas’ distribution system and are used to liquefy and store pipeline gas during the warmer months for use during the heating season. During the summer injection season, excess pipeline capacity is used to deliver and store gas in market area storage facilities, located in the New York and Pennsylvania region. Stored gas is withdrawn during the winter season to supplement pipeline supplies in order to meet firm heating demand. NSTAR Gas has firm storage contracts and total storage capacity entitlements of nearly 8 billion cubic feet (Bcf).

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

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

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

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Franchises

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

Unregulated Operations

NSTAR’s unregulated operations segment engages in businesses that include district energy operations, telecommunications and liquefied natural gas service. District energy operations are provided through its Advanced Energy Systems, Inc. (AES) subsidiary that sells chilled water, steam and electricity to hospitals and teaching facilities located in Boston’s Longwood Medical Area. AES expanded its Medical Area Total Energy Plant (MATEP) facility in 2003 to provide additional capacity. A former NSTAR subsidiary, NSTAR Steam Corporation, sold its assets to a non-affiliated entity in September 2005. Telecommunications services are provided through NSTAR Com, which installs, owns, operates and maintains a wholesale transport network for other telecommunications service providers in the metropolitan Boston area to deliver voice, video, data and internet services to customers. Revenues earned from NSTAR’s unregulated operations accounted for approximately 4% of consolidated operating revenues in 2005, 2004 and 2003.

RCN Joint Venture, Investment Conversion and Abandonment

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

Regulation

The Energy Policy Act of 2005 repealed the 70-year-old Holding Company Act, which established a regulatory regime overseen by the Securities and Exchange Commission, and replaced it with a new statute focused on increased access to holding company books and records to assist the FERC and state utility regulators in protecting customers of regulated utilities. On December 8, 2005, the FERC finalized rules to implement the Congressionally mandated repeal of the Public Utility Holding Company Act (PUHCA) of 1935 and enactment of the PUHCA of 2005. Congress mandated that the FERC issue its final rules by December 8, 2005, for the rules to be in place by February 8, 2006, the date the 1935 law was repealed and the new PUHCA 2005 took effect. NSTAR is a holding company exempt from the provisions of the Public Utility Holding Company Act of 1935, as amended, except for Section 9(c)(2). NSTAR anticipates filing for a waiver from the PUHCA 2005 revisions in the first quarter of 2006.

NSTAR Electric, NSTAR Gas, and Boston Edison’s wholly-owned regulated subsidiary, Harbor Electric Energy Company, operate primarily under the authority of the MDTE, whose jurisdiction includes supervision over retail rates for distribution of electricity, natural gas and financing and investing activities. In addition, the FERC has

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jurisdiction over various phases of NSTAR Electric and NSTAR Gas utility businesses, conditions under which natural gas is 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:

(in thousands)	2006		2007-2010
Plant expenditures	$	408,000	$	1,200,000
Long-term debt	$	123,140	$	1,247,857

Plant expenditures include costs related to NSTAR’s 345kV transmission project that in the aggregate is expected to total approximately $220 million. A significant portion of these costs ($120 million) was incurred in 2005 ($11 million spent in 2004) and the remaining balance will be expended in 2006. In the second quarter of 2005, NSTAR began construction of a switching station in Stoughton, Massachusetts and a 345kV transmission line that will connect the switching station to South Boston. As of December 31, 2005, construction that is part of this project is also in progress on the expansion of two existing substations. 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 NSTAR’s Settlement Agreement approved by the MDTE on December 30, 2005, NSTAR Electric has provided the MDTE with a list of potential projects that are designed to improve reliability and safety. These projects are 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. The capital component of these programs is included in the above 2006 plant expenditure estimate.

Plant expenditures in 2005 were approximately $383.6 million and consisted primarily of additions to NSTAR’s distribution and transmission systems with a significant amount related to the 345kV project previously referenced. The majority of these expenditures were for system reliability and performance improvements, customer service enhancements and capacity expansion to meet expected growth in the NSTAR 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” and “Liquidity and Capital Resources” sections of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Seasonal Nature of Business

NSTAR Electric’s kilowatt-hour sales and revenues are typically higher in the winter and summer than in the spring and fall as sales tend to vary with weather conditions. NSTAR Gas’ sales are positively impacted by colder weather because a substantial portion of its customer base uses natural gas for space heating purposes. Refer to the “Selected Quarterly Consolidated Financial Data” section in Item 6, “Selected Consolidated Financial Data” for specific financial information by quarter for 2005 and 2004.

Competitive Conditions

The electric and natural gas industries, in general, have continued to change in response to legislative, regulatory and marketplace demands for improved customer service at lower prices. These pressures have resulted in an

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increasing trend in the industry to seek efficiencies and other benefits through business combinations. NSTAR operates in this marketplace by combining the resources of its utility subsidiaries activities in the transmission and distribution of energy.

Environmental Matters

NSTAR’s subsidiaries are subject to numerous federal, state and local standards with respect to the management of wastes and other environmental considerations. NSTAR subsidiaries face possible liabilities as a result of involvement in several multi-party disposal sites, state-regulated sites or third party claims associated with contamination remediation. NSTAR 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 P, for more information.

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

Number of Employees

As of December 31, 2005, NSTAR had approximately 3,050 employees, including approximately 2,150, or 70%, who are represented by three 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. Approximately 60 employees of Advanced Energy Systems’ MATEP subsidiary are represented by Local 877, the International Union of Operating Engineers, AFL-CIO, under a contract that expires on September 30, 2006.

Management believes it has satisfactory relations with its employees.

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

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

Item 1A. Risk Factors

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

Our electric and gas 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.

NSTAR’s electric and gas operations, including the rates charged, are regulated by the FERC and the MDTE. In addition, NSTAR’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 and gas businesses.

Under Massachusetts law, no other entity may provide electric or gas delivery service to retail customers within NSTAR’s service territory without the written consent of NSTAR Electric and/or NSTAR Gas. Although not a

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trend, NSTAR’s operating utility companies could be exposed to municipalization risk, whereby a municipality could acquire the electric or gas delivery assets located in that city or town and take over the customer delivery service, thereby reducing NSTAR’s revenues. Any such action would require numerous legal and regulatory consents and approvals. In addition, NSTAR expects that any municipalization would require that NSTAR be compensated for its assets assumed.

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

NSTAR and its subsidiaries are 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 NSTAR’s results of operations.

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

NSTAR is subject to actual or potential claims and lawsuits involving environmental remediation activities for power generating sites previously owned and other potentially unidentified sites. NSTAR divested all of 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 NSTAR’s current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, NSTAR does not believe that its known environmental remediation responsibilities will have a material adverse effect on NSTAR’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 NSTAR’s results of operations, cash flows or financial position.

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

Our business, which involves the transmission and distribution of natural gas and 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 NSTAR’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 NSTAR 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.

NSTAR 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 and ultimately have an adverse impact on the market price of our common shares. 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 electric and gas businesses are sensitive to variations in weather and have seasonal variations. In addition, severe-storm related disasters could adversely affect the Company.

Sales of electricity and gas 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

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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, NSTAR’s rate regulated subsidiaries 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 NSTAR’s results of operations, cash flows or financial position.

Item 1B. Unresolved Staff Comments

None

Item 2. Properties

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

At December 31, 2005, the NSTAR Electric primary and secondary transmission and distribution system consisted of approximately 21,550 circuit miles of overhead lines, approximately 12,125 circuit miles of underground lines, 256 substation facilities and approximately 1,145,550 active customer meters.

NSTAR Electric’s high-voltage transmission lines are generally located on land either owned or subject to perpetual and exclusive easements in its favor. Its low-voltage distribution lines are located principally on public property under permits granted by municipal and other state authorities. During 2005, NSTAR Electric commenced construction on a 345 kV transmission project that will add approximately 18 miles of transmission lines. To date, this project is approximately 60% complete and is anticipated to be placed in service in 2006.

NSTAR Gas’ principal natural gas properties consist of distribution mains, services and meters necessary to maintain reliable service to customers. In addition, it owns an office and service building, three district office buildings and several natural gas receiving and take stations. At December 31, 2005, the gas system included approximately 3,012 miles of gas distribution lines, approximately 181,816 services and approximately 283,060 customer meters together with the necessary measuring and regulating equipment. In addition, Hopkinton LNG Corp. owns a liquefaction and vaporization plant, a satellite vaporization plant and above ground cryogenic storage tanks having an aggregate storage capacity equivalent to 3.5 Bcf of natural gas.

District energy operations consist of AES’ cogeneration facility located in the Longwood Medical Area of Boston. MATEP provides steam, chilled water and electricity to over 9 million square feet of medical and teaching facilities. NSTAR Steam Corporation sold its assets to a non-affiliated entity in September 2005. NSTAR Steam’s distribution system primarily consisted of approximately 3.5 miles of steam lines utilized to provide service to customers in Cambridge, MA.

Item 3. Legal Proceedings

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

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

There were no matters submitted to a vote of security holders during the fourth quarter of 2005.

Item 4A. Executive Officers of Registrant

Identification of Executive Officers

Name of Officer	Position and Business Experience	Age at December 31, 2005
Thomas J. May	Chairman, President (since 2002) and Chief Executive Officer and a Trustee	58
Douglas S. Horan	Senior Vice President - Strategy, Law and Policy, Secretary and General Counsel	56
James J. Judge	Senior Vice President, Treasurer and Chief Financial Officer	49
Timothy R. Manning	Senior Vice President - Human Resources (since 2002); formerly Vice President Human Resources (2001); Director of Employee and Labor Relations (1999-2001)	54
Joseph R. Nolan, Jr.	Senior Vice President - Customer & Corporate Relations (since 2002); formerly Senior Vice President - Corporate Relations (2000-2002)	42
Werner J. Schweiger	Senior Vice President - Operations (since 2002); formerly Vice President, Office of Electric Operations/Transmission and Distribution Management, Keyspan Energy Corporation (1997-2002)	46
Eugene J. Zimon	Senior Vice President - Information Technology (since 2001); formerly Vice President, Business Development for Utilities, Oracle Corporation (2000-2001)	57
Robert J. Weafer, Jr.	Vice President, Controller and Chief Accounting Officer	58

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PART II

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

(a) Market Information

The NSTAR Common Shares, $1 par value, are listed on the New York and Boston Stock Exchanges under the symbol “NST.” NSTAR’s Common Shares closing market price at December 31, 2005 was $28.70 per share.

The NSTAR Common Shares high and low sales prices as reported by the New York Stock Exchange composite transaction reporting system for each of the quarters in 2005 and 2004 were as follows:

	2005				2004
	High		Low		High		Low
First quarter	$	29.68	$	26.33	$	26.43	$	24.00
Second quarter	$	30.98	$	26.80	$	26.00	$	22.65
Third quarter	$	31.46	$	28.55	$	25.25	$	23.00
Fourth quarter	$	30.02	$	24.90	$	27.23	$	24.09

At NSTAR’s Annual Meeting of Shareholders held on April 28, 2005, shareholders approved an increase in the number of the Company’s authorized shares from 100 million to 200 million. Subsequently, the Board of Trustees approved a two-for-one stock split of NSTAR’s common shares, in the form of a 100% common share dividend, to shareholders of record on May 16, 2005. The new shares were issued on June 3, 2005. The Company’s intent in effecting a stock split in the form of a stock dividend was to increase the number of outstanding common shares and to reduce the per share stock price thereby making it more accessible to investors. Common equity, common shares, and stock option activity for all periods presented have been restated to give retroactive recognition to the stock split. In addition, all references in the financial statements and notes to the financial statements, to weighted average number of basic and diluted shares, and per share amounts of the Company’s common shares have been restated to give retroactive recognition to the stock split.

(b) Holders

As of December 31, 2005, there were 23,575 registered holders of NSTAR Common Shares.

(c) Dividends

Dividends declared per Common Share for each quarter of 2005 and 2004 were as follows:

	2005			2004
First quarter	$	0.29		$	0.2775
Second quarter	$	0.29		$	0.2775
Third quarter	$	0.29		$	0.2775
Fourth quarter	$	0.3025	*	$	0.29

NSTAR paid common share dividends to shareholders totaling $123.8 million and $117.9 million in 2005 and 2004, respectively.

* As a result of a change in NSTAR’s Board of Trustee meetings schedule in 2005, the fourth quarter dividend typically declared in December was approved on January 26, 2006. The dividend payment schedule remains unchanged.

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(d) Securities authorized for issuance under equity compensation plans

The following table provides information about NSTAR’s equity compensation plans as of December 31, 2005.

Plan Category	Number of securities to be issued upon exercise of outstanding options	Weighted average exercise price of outstanding options		Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by shareholders	2,588,401	$	24.05	2,116,472
Equity compensation plans not approved by shareholders	—		—	—
Total	2,588,401	$	24.05	2,116,472

(e) Purchases of equity securities

Common Shares of NSTAR issued under the NSTAR Dividend Reinvestment and Direct Common Shares Purchase Plan, the 1997 Share Incentive Plan and the NSTAR Savings Plan in connection with common share grants and the exercise of stock options may consist of newly issued shares from the Company or shares purchased in the open market by the Company or an independent agent. During the three-month period ended December 31, 2005, the shares listed below were acquired in the open market primarily in connection with the NSTAR Savings Plan.

	Total Number of Common Shares Purchased	Average Price Paid Per Share
October	101,755	$	27.10
November	115,138	$	27.34
December	20,180	$	27.98

Item 6. Selected Consolidated Financial Data

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

(in thousands, except per share data)	2005		2004		2003		2002		2001
Operating revenues	$	3,243,120	$	2,954,332	$	2,911,711	$	2,690,625	$	3,181,167
Net income (loss)(a)	$	196,135	$	188,481	$	181,574	$	161,707	$	(2,426	)
Earnings (loss) per common share:
Basic (a)	$	1.84	$	1.77	$	1.71	$	1.52	$	(0.02	)
Diluted (a)	$	1.83	$	1.76	$	1.70	$	1.52	$	(0.02	)
Total assets	$	7,645,564	$	7,391,356	$	6,614,186	$	6,628,396	$	5,626,040
Long-term debt (b)	$	1,614,411	$	1,792,654	$	1,602,402	$	1,645,465	$	1,377,899
Transition property securitization (b)	$	787,966	$	308,748	$	377,150	$	445,890	$	513,904
Preferred stock of subsidiary (b)	$	43,000	$	43,000	$	43,000	$	43,000	$	43,000
Cash dividends declared per common share (c)	$	1.1725	$	1.1225	$	1.0875	$	1.065	$	1.0375

(a) 2002 and 2001 include non-cash, after-tax charges of $17.7 million and $173.9 million, or $0.17 per share and $1.64 per basic share, respectively, related to NSTAR’s investment in RCN Corporation.

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

(c) As a result of a change in NSTAR’s Board of Trustee meetings schedule in 2005, the fourth quarter dividend typically declared in December was approved on January 26, 2006. The dividend payment schedule remains unchanged.

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Selected Quarterly Consolidated Financial Data (Unaudited)

(in thousands, except earnings per share)
	Operating Revenues		Operating Income		Net Income		Earnings Per Share (a)
							Basic		Diluted
2005
First quarter	$	880,045	$	86,132	$	46,269	$	0.43	$	0.43
Second quarter	$	692,005	$	76,088	$	33,151	$	0.31	$	0.31
Third quarter	$	858,495	$	119,478	$	78,010	$	0.73	$	0.72
Fourth quarter	$	812,575	$	73,872	$	38,705	$	0.36	$	0.36
2004
First quarter	$	809,908	$	87,507	$	49,716	$	0.47	$	0.46
Second quarter	$	649,787	$	73,407	$	37,525	$	0.35	$	0.35
Third quarter	$	781,510	$	101,268	$	63,281	$	0.60	$	0.59
Fourth quarter	$	713,127	$	76,146	$	37,959	$	0.36	$	0.35

(a) The sum of the quarters may not equal basic and diluted annual earnings per share.

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

Overview

NSTAR (or the Company) is a holding company engaged through its subsidiaries in the energy delivery business serving approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric distribution customers in 81 communities and approximately 300,000 natural gas distribution customers in 51 communities. NSTAR’s retail utility subsidiaries are Boston Edison Company (Boston Edison), Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas). Its wholesale electric subsidiary is Canal Electric Company (Canal). NSTAR’s three retail electric companies collectively operate as “NSTAR Electric.” Reference in this report to “NSTAR” shall mean the registrant NSTAR or NSTAR and its subsidiaries as the context requires. Reference in this report to “NSTAR Electric” shall mean Boston Edison, ComElectric and Cambridge Electric together. NSTAR’s non-utility, unregulated operations include district energy operations through its Advanced Energy Systems, Inc. subsidiary, telecommunications operations (NSTAR Communications, Inc. (NSTAR Com)) and a liquefied natural gas service company (Hopkinton LNG Corp.). Utility operations accounted for approximately 96% of consolidated operating revenues in 2005, 2004 and 2003.

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

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 NSTAR Electric to lower its transition rates by $20 million 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 the transition rates, through 2012. For NSTAR Gas customers, the settlement includes an adjustment to the cost of gas adjustment clause to defer recovery of approximately $18.5 million beginning January 2006. NSTAR Gas would be allowed to recover this deferral, with interest at the effective prime rate, over a twelve-month period commencing no earlier than May 1, 2006.

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Major components of the agreement include:

• A reduction in annual transition rates of $20 million effective January 1, 2006 and on May 1, 2006, a distribution rate increase of $30 million 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%.

• NSTAR Electric 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 Cambridge Electric, ComElectric and Canal into Boston Edison; the merger will require approval by the MDTE.

• 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 NSTAR 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.

Cautionary Statement

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

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

• impact of continued cost control procedures on operating results

• weather conditions that directly influence the demand and cost for electricity and natural gas and major storms

• 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

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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 union contract negotiations

• impact of uninsured losses

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

• future economic conditions in the regional and national markets

• ability to maintain current credit ratings, and

• the impact of terrorist acts

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

Critical Accounting Policies and Estimates

NSTAR’s discussion and analysis of its financial condition, results of operations and cash flows are based upon the accompanying Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of these Consolidated Financial Statements required management to make estimates and 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. NSTAR believes that its accounting policies and estimates that are most critical to the reported results of operations, cash flows and financial position are described below.

a. Revenue Recognition

Utility revenues are based on authorized rates approved by the MDTE and FERC. Revenues related to the sale, transmission and distribution of delivery service 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 systematic meter readings throughout the month. Meters that are not read during a given month are estimated and trued-up in a future period. At the end of each month, amounts of energy delivered to customers since the date of the last billing date are estimated and the corresponding unbilled revenue is estimated. This unbilled electric revenue is estimated each month based on daily generation volumes (territory load), estimated line losses and applicable customer rates. Unbilled natural gas revenues are estimated based on estimated purchased gas volumes, estimated gas losses and tariffed rates in effect. Accrued unbilled revenues recorded in the accompanying Consolidated Balance Sheets as of December 31, 2005 and 2004 were $59 million and $54 million, respectively.

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

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

b. Regulatory Accounting

NSTAR follows accounting policies prescribed by GAAP, the FERC and the MDTE. As a rate-regulated company, NSTAR’s utility subsidiaries are subject to the Financial Accounting Standards Board (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 revenues and expenses from those of other businesses and industries. NSTAR’s energy delivery businesses remain subject to rate-regulation and continue to meet the criteria for application of SFAS 71. This ratemaking process results in the recording of regulatory assets based on the probability of current and future cash inflows. Regulatory assets represent incurred or accrued costs that have been deferred because they are probable of future recovery from customers. As of December 31, 2005 and 2004, NSTAR has recorded regulatory assets of $2.7 billion and $2.9 billion, respectively. NSTAR continuously reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. NSTAR expects to fully recover these regulatory assets in its rates. If future recovery of costs ceases to be probable, NSTAR would be required to charge these assets to current earnings. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.

c. Pension and Other Postretirement Benefits

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

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

There were no significant changes to NSTAR’s pension benefits in 2005, 2004 and 2003 that had an impact on recorded pension costs. As further described inNote I to the accompanying Consolidated Financial Statements, NSTAR’s discount rate for December 31, 2005 and 2004 was 5.75% and aligns with market conditions and the characteristics of NSTAR’s 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 an impact on reported pension costs in future years in accordance with the cost recognition approach of SFAS 87. This impact, however, will be mitigated through NSTAR’s regulatory accounting treatment of qualified pension and PBOP costs. (See further discussion of regulatory accounting treatment below.) In determining pension obligation and cost amounts, these assumptions may change from period to period, and such changes could result in material changes to recorded pension and PBOP costs and funding requirements.

NSTAR’s Pension Plan (the Plan) assets, which partially consist of equity investments, are affected by fluctuations in the financial markets. These fluctuations in market returns will have an impact on pension costs in future periods.

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

(in thousands)
Actuarial Assumption	Change in Assumption	Impact on Projected Benefit Obligation Increase/(Decrease)			Impact on 2005 Cost 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		N/A		$	(4,410	)
Decrease in expected long-term rate of return on plan assets	50 basis points		N/A		$	4,410
Other Postretirement Benefits:
Increase in discount rate	50 basis points	$	(41,073	)	$	(3,068	)
Decrease in discount rate	50 basis points	$	46,119		$	3,378
Increase in expected long-term rate of return on plan assets	50 basis points		N/A		$	(1,453	)
Decrease in expected long-term rate of return on plan assets	50 basis points		N/A		$	1,453

N/A - 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, NSTAR considers past performance and economic forecasts for the types of investments held by the Plan as well as the target allocation for the investments over a 20-year time period. In 2005, NSTAR 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 NSTAR’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 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, NSTAR 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, NSTAR anticipates that it will not contribute to the Plan in 2006.

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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 NSTAR’s results of operations or cash flows because these costs will be collected from customers through NSTAR’s transition charge filings with the MDTE.

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

The Maine Yankee nuclear unit (MY) was notified on October 3, 2005 by the U.S. Nuclear Regulatory Commission (NRC) that its former plant site has been decommissioned in accordance with NRC procedures. The NRC has amended MY’s license, reducing the land under the license from approximately 179 acres to the 12 acre Independent Spent Fuel Storage Installation (ISFSI) that includes a dry cask storage facility, and marks the first time a commercial nuclear power plant in the United States has been fully decommissioned with all plant buildings removed. MY’s amended license will continue to apply to the ISFSI where spent nuclear fuel from the plant’s 23 years of operation is stored. MY remains responsible for the security and protection of the ISFSI and is required to maintain a radiation monitoring program at the site.

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, $149.3 million for YA and $242.5 million for MY. Of these amounts, NSTAR Electric is obligated to pay $72.2 million towards the decommissioning of CY, $20.9 million toward YA, and $9.7 million toward MY. These amounts are recorded in the accompanying Consolidated Balance Sheets as Energy contract liabilities with a corresponding Regulatory asset and do not impact the current results of operations and cash flow. These estimates may be revised from time to time based on information available to the Yankee Companies regarding future costs.

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

CY’s estimated decommissioning costs increased significantly in 2003 to reflect 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 NSTAR Electric, 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

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in the termination litigation is drawing to a close, and a trial has been scheduled for May 2006. NSTAR cannot predict the timing or outcome of the litigation with Bechtel but does not expect a material impact on NSTAR’s financial position, results of operation or cash flows.

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, NSTAR Electric is obligated to pay $8.8 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. NSTAR Electric cannot predict the timing or the ultimate outcome of these settlement discussions.

Derivative Instruments

Energy 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. NSTAR 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.”

NSTAR Electric 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, NSTAR, as of December 31, 2004, had four remaining contracts that were recorded at fair value on the accompanying Consolidated Balance Sheets. On March 1, 2005, NSTAR closed on a securitization financing for $674.5 million to, in part, finance the buy-out of these remaining four contracts that were classified as derivative instruments at December 31, 2004. These four contracts had an aggregate fair value of approximately $472 million at December 31, 2004 and were therefore removed as a derivative instrument from Deferred credits - Energy contracts, along with the offsetting regulatory asset, on the accompanying

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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 electric distribution companies’ transition charge. At December 31, 2005, NSTAR does not have any contracts that continue to be classified as derivative instruments. Refer to the accompanying Consolidated Financial Statements,Note O, for more detail on the buy-out of certain purchase power contracts.

Hedging Agreements

On February 28, 2005, the MDTE approved a petition by NSTAR Gas to change a portion of its gas procurement practices. As approved, NSTAR Gas began purchasing financial contracts based upon NYMEX natural gas futures in order to reduce cash flow variability associated with the purchase price for approximately one-third of its natural gas purchases. Ultimately, this will minimize fluctuations in prices to NSTAR firm gas sales customers. NSTAR Gas will not take physical delivery of gas when the financial contracts are executed. These contracts qualify as derivative financial instruments and specifically cash flow hedges under SFAS 133, as amended by SFAS 149. Accordingly, the fair value of these instruments will be recognized on the accompanying Consolidated Balance Sheet as a deferred asset or liability representing amounts due from or payable to the counter parties of NSTAR Gas. All costs incurred are included in the firm sales Cost of Gas Adjustment Clause (CGAC). Therefore, NSTAR Gas will record an offsetting regulatory asset or liability. Management has begun to implement this practice with two major financial institutions. Currently, these derivative contracts extend through April 2006. At December 31, 2005, NSTAR has recorded a liability and a corresponding regulatory asset of $0.3 million reflecting the fair value of these 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.

NSTAR adopted FIN 47 at December 31, 2005, as required. The recognition of an ARO within its regulated utility businesses has no impact on NSTAR’s earnings. In accordance with SFAS 71, for its rate-regulated utilities, NSTAR established a regulatory asset to recognize future recoveries through depreciation rates for the recorded ARO. NSTAR 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, NSTAR recognized an asset retirement cost of $0.4 million as an increase in utility property, an asset retirement liability of $9.4 million and a regulatory asset of $9 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 $8.8 million and $8.4 million, respectively.

For NSTAR’s regulated utility businesses, the ultimate cost to remove utility plant from service (cost of removal) is recognized as a component of depreciation expense in accordance with approved regulatory treatment. As of December 31, 2005 and 2004, the estimated amount of the cost of removal included in regulatory liabilities was approximately $259 million based on the estimated cost of removal component in current depreciation rates.

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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.

NSTAR has three wholly owned special purpose subsidiaries, BEC Funding LLC., established in 1999, BEC Funding II, LLC and CEC Funding, LLC both established in 2004, to undertake the sale of $725 million, $265.5 million and $409 million, respectively, in notes to a special purpose trust created by two Massachusetts state agencies. NSTAR consolidates these entities. As part of NSTAR’s assessment of FIN 46R and, for compliance at December 31, 2003 or 2004, NSTAR reviewed the substance of these entities to determine if it is still proper to consolidate these entities. Based on its review, NSTAR has concluded that BEC Funding LLC, BEC Funding II, LLC and CEC Funding, LLC are VIEs and should continue to be consolidated by NSTAR.

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

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

New Accounting Standards

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” This Standard addresses the accounting for transactions in which a company receives employee services in exchange for (a) equity instruments of the company or (b) liabilities that are based on the fair value of the company’s equity instruments or that may be settled by the issuance of such equity instruments. This Standard eliminates the ability to account for share-based compensation transactions using Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and requires that such transactions be accounted for using a fair-value-based method. The Standard is effective for the first quarter of 2006. NSTAR is currently assessing its valuation options allowed in this Standard but, preliminarily, expects this Standard to impact annual pre-tax earnings by approximately $1.5 million. In addition, the Company will use the Modified Prospective approach and will utilize the Black-Scholes Option pricing model to determine the fair value of its compensation expense for these option grants.

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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, NSTAR 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. NSTAR Electric and NSTAR Gas are required to report annually to the MDTE concerning their performance as to each measure and are subject to maximum penalties of up to two percent of transmission and distribution revenues should performance fail to meet the applicable benchmarks.

NSTAR 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, each NSTAR utility subsidiary makes a service quality performance filing with the MDTE. Any settlement or rate order that would result in a different liability level from what has been accrued would be adjusted in the period that the MDTE issues an order determining the amount of any such liability.

On March 1, 2005, NSTAR Electric and NSTAR Gas filed their 2004 Service Quality Reports with the MDTE that demonstrated the Companies 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.

As of December 31, 2005, NSTAR has determined that for 2005, two of its electric subsidiaries are in a combined penalty position of approximately $0.4 million relating to their applicable service quality indicators. This penalty position is primarily due to service interruptions caused by the severe winter storms experienced earlier in the year. As a result, NSTAR has recorded a liability for this obligation. Since 2001, NSTAR Electric and NSTAR Gas have not been in a penalty position and therefore, the 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. NSTAR cannot predict the outcome or timing of this proceeding.

The Settlement Agreement approved by the MDTE on December 30, 2005, established additional performance measures applicable to NSTAR’s rate regulated subsidiaries. NSTAR Gas will establish and submit a service quality measure based on separate leaks per mile metrics for bare-steel mains and unprotected, coated-steel mains. A specific proposal to implement this performance benchmark will be submitted to the MDTE for approval by on or before July 1, 2006 and will be subject to a maximum penalty or incentive of up to $500,000. The Settlement Agreement also establishes, for NSTAR Electric, a performance benchmark relating to poor performing circuits, with a maximum penalty or incentive of up to $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

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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 NSTAR Electric had approximately 32%, 24% and 26%, 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, NSTAR Electric 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 February 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 $20 million effective January 1, 2006 and by $30 million on May 1, 2006 and are deferred with carrying charges at a rate of 10.88%.

In December 2004, NSTAR Electric 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 each retail electric subsidiary 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.

On October 19, 2005, the MDTE approved a settlement agreement between Cambridge Electric, ComElectric and the Attorney General of the Commonwealth of Massachusetts to resolve issues relating to the reconciliation of transition, standard offer and basic service costs for 2003 and 2004. This settlement agreement had no material effect on NSTAR’s consolidated results of operations, cash flows and financial condition for a reporting period. The reconciliation of transmission costs and revenues was not resolved by settlement and will be decided by the MDTE after a hearing if there is no settlement on this issue. Settlement discussions with an intervener and the Attorney General of the Commonwealth of Massachusetts are ongoing with respect to Boston Edison’s 2003 and 2004 transmission reconciliation filing. 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 decided by the MDTE in a future hearing. NSTAR Electric cannot predict the timing or the ultimate outcome of these settlement discussions or adjustments.

c. Wholesale Market and Transmission 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. NSTAR Electric’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.

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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, by March 6, 2006. NSTAR cannot predict the actual impact these changes will have on NSTAR Electric 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 NSTAR’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.

Cambridge Electric and ComElectric filed proposed changes to their component of the ISO OATT with the FERC on March 30, 2005 to provide for consistent application of the OATT among all NSTAR Electric

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companies. The new tariffs became effective on June 1, 2005; however, the FERC set issues raised in the proceeding for hearing. Settlement discussions with an intervener and the Attorney General of the Commonwealth of Massachusetts are ongoing. NSTAR cannot predict the timing or the ultimate resolution of this proceeding.

d. Gas Rates

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

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

On February 28, 2005, the MDTE approved a petition by NSTAR Gas to change a portion of its gas procurement practices. NSTAR Gas will purchase financial contracts based upon NYMEX natural gas futures in order to lock in prices for approximately one-third of its projected normal winter gas requirements. NSTAR Gas will not be taking physical delivery of the gas when the financial contracts are executed. NSTAR Gas has commenced to implement this practice after having completed contract negotiations with major financial institutions. All costs incurred or benefits recovered will continue to be included in the CGAC. NSTAR Gas accounts for its gas procurement contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities (SFAS 133) and related interpretations.

Due to fluctuations in wholesale natural gas prices, NSTAR Gas is allowed to recover its gas supply costs from firm sales customers through the CGAC. The 2004-2005 winter season CGAC factor was revised downward from earlier in 2004 to reflect decreases in the cost of gas caused by varying market conditions. NSTAR Gas’ CGAC factor received MDTE approval of $0.9968/therm effective November 1, 2004. On February 1, 2005, an approved rate of $0.8500/therm was established until May 1, 2005 when a rate of $0.7501/therm was approved. On September 1, 2005 and on November 1, 2005, due to rapid increases in natural gas prices, the MDTE approved CGAC factors of $1.2232/therm and $1.4570/therm, respectively.

On December 30, 2005, the MDTE approved the rate Settlement Agreement which provided for a reduction in the CGAC factor from $1.4570/therm to $1.3955/therm effective January 1, 2006.

Prior to 2004-2005, the winter season CGAC factor was revised upward to reflect increases in the cost of gas caused by varying market conditions. The CGAC factor for the winter of 2003-2004 ranged from $0.8121/therm to $0.8925; in the winter of 2002-2003, the CGAC ranged from $0.6139/therm to $0.8936/therm.

Stock Split

At NSTAR’s Annual Meeting of Shareholders held on April 28, 2005, shareholders approved an increase in the number of the Company’s authorized shares from 100 million to 200 million common shares. The Board of Trustees subsequently approved a two-for-one stock split of NSTAR common shares, in the form of a 100% common share dividend, for shareholders of record on May 16, 2005. The new shares were issued on June 3, 2005. The Company’s intent in effecting a stock split in the form of a stock dividend was to increase the number of outstanding common shares and to reduce the per share stock price thereby making it more accessible to investors.

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Sale of Properties

On December 28, 2005, ComElectric sold a former electric generation station site in New Bedford, Massachusetts for $12 million. NSTAR anticipates that most of the proceeds from the sale will be applied against ComElectric’s transition charge. The sale and regulatory treatment of the proceeds remains subject to MDTE approval. As a result, this transaction had no impact on current year earnings.

On September 8, 2005, NSTAR sold the assets of its wholly-owned unregulated subsidiary, NSTAR Steam Corporation to a non-affiliated company for $3.5 million, realizing a pre-tax gain on the sale of $2.5 million. Also in September 2005, NSTAR sold a parcel of land in Cambridge Massachusetts for $2 million. No gain was recognized from this land sale, as Cambridge Electric will refund these proceeds to its customers.

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.

General Legal Matters

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

RCN Corporation (RCN) Share Abandonment Tax Treatment

On December 24, 2003, NSTAR exited its investment in RCN and formally abandoned its 11.6 million shares of RCN common stock. As a result, NSTAR recorded a pre-tax charge of approximately $6.8 million, or $0.08 per share reflecting the writedown of its investment to zero as of December 31, 2003. NSTAR determined that the abandonment at that time was the most tax efficient, cost effective and expedient means to exit its RCN investment. NSTAR also determined that the benefit of a tax realization event at that time and in that manner outweighed any benefit that it would likely realize from any other alternative, including the future sale of such shares in an orderly fashion consistent with all laws, rules and regulations.

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

It is NSTAR’s tax accounting policy to not recognize tax benefits associated with an uncertain tax position until it is probable that such tax benefit will ultimately be realized. Since NSTAR is under continuous audit by the Internal Revenue Service (IRS), NSTAR consulted with its independent tax advisors and determined that it could not conclude that it is probable that the tax deduction related to the abandonment of its RCN investment will be sustained. Accordingly, NSTAR accrued a tax reserve so as to not record the tax benefit of the uncertain tax position.

The Company believes it is more likely than not that it is entitled to this ordinary loss deduction, but expects the IRS will review this transaction and it is possible that the IRS will disagree with the Company’s position. In accordance with the Company’s tax policy as it relates to uncertain tax positions, NSTAR established a loss contingency of approximately $44.4 million at December 31, 2003. This amount

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represents the tax impact to the Company should the ordinary loss ultimately be recharacterized to a capital loss and would be reclassified as a tax valuation allowance. During 2005, the Company recognized approximately $4.7 million in tax benefits related to capital tax gain transactions. As a result, the Company reduced its tax loss contingency by a corresponding amount. Therefore, as of December 31, 2005, the tax loss contingency is approximately $39.7 million. This contingent liability is recorded as part of Deferred credits - Other on the accompanying Consolidated Balance Sheets.

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

Results of Operations

The following section of MD&A compares the results of operations for each of the three fiscal years ended December 31, 2005, 2004 and 2003 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

Executive Summary

Earnings per common share were as follows:

	Years ended December 31,
	2005		2004		% Change
Basic	$	1.84	$	1.77	4.0
Diluted	$	1.83	$	1.76	4.0

Net income was $196.1 million for 2005 compared to $188.5 million for 2004. Factors that contributed to the $7.6 million, or 4%, increase in 2005 earnings include:

• Recognition of incremental incentives as approved by the MDTE for successfully lowering transition charges (approximately $9 million) and incentives related to NSTAR’s demand-side management programs (approximately $0.9 million)

• Higher electric distribution revenues ($16.5 million) that primarily resulted from a 2.9% increase in energy sales. Cooling and heating degree days increased 41.3% and decreased 1.0%, respectively, over 2004.

• Higher electric transmission rates due to FERC approval of the inclusion of 50% transmission CWIP in rate base and additional transmission plant in service ($16.4 million)

• Decreased income tax expense of approximately $9.0 million derived from successful resolution of uncertain tax positions and positive adjustments to NSTAR’s RCN tax loss contingency through a related capital gain transaction

These increases were partially offset by:

• Higher operations and maintenance expense due to costs associated with:

• severe storms (approximately $8.6 million)

• costs associated with facilities consolidation (approximately $3 million)

• incremental costs associated with a work stoppage by union employees ($3 million)

• a net increase of approximately $4.7 million related to an environmental reserve

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• Lower firm gas revenues due to lower firm gas sales caused by warmer winter weather ($3.6 million)

• Higher short-term debt interest costs due to higher level and rates on debt outstanding ($4.8 million)

• The absence in 2005 of $4.7 million in cost reconciliation adjustments that increased revenues in 2004

In 2005, NSTAR closed on a $674.5 million securitization financing transaction. The net proceeds were used primarily to make liquidation payments required in connection with the termination of obligations under certain purchase power contracts (approximately $554.3 million) and to repay $150 million of outstanding debt at ComElectric.

Net cash used in operations in 2005 was $26.9 million, a level that was significantly lower than 2004, and resulted from the effect of the purchase power agreements buy-out payments of $653.2 million. Certain of these buyout costs ($554.3 million) were financed with the proceeds from NSTAR Electric’s securitization financing. Cash generated from operations was primarily used to fund approximately $383.6 million of net plant expenditures. The Company’s plant expenditures will continue to provide improvements to its operational performance. Net financing activities provided approximately $400.5 million of cash and includes the securitization financing referenced above.

Energy Sales

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

	Years ended December 31,
	2005	2004	% Change
Retail Electric Sales - MWH
Residential	6,773,925	6,564,494	3.2
Commercial	13,117,869	12,693,217	3.3
Industrial	1,624,422	1,651,389	(1.6	)
Other	165,158	168,733	(2.1	)
Total retail sales	21,681,374	21,077,833	2.9
	Years ended December 31,
	2005	2004	% Change
Firm Gas Sales - BBTU
Residential	21,974	23,073	(4.8	)
Commercial	15,416	15,692	(1.8	)
Industrial and other	8,115	8,202	(1.1	)
Total firm sales	45,505	46,967	(3.1	)

Energy sales of electricity in 2006 are expected to grow at a rate of approximately 1%. Firm gas energy sales are expected to grow at a rate of 3%. However, NSTAR forecasts its electric and natural gas sales based on normal weather conditions. Actual results may differ from those projected due to actual weather conditions, energy conservation, and other factors. Refer to the “Cautionary Statement” in this section.

Weather Conditions

In terms of customer sector characteristics, industrial sales are less sensitive to weather than residential and commercial sales, which are influenced by temperature fluctuations. 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 31% and 61%, respectively, of NSTAR’s total sales mix

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for 2005 and provided 43% and 52% of distribution and transmission revenues, respectively. Refer to the “Electric revenues” section below for a more detailed discussion. Industrial sales are primarily influenced by national and local economic conditions and sales to these customers reflect a sluggish economic environment and decreased manufacturing production.

	2005		2004		Normal 30-Year Average
Heating degree-days	6,437		6,500		6,445
Percentage (warmer) colder than prior year	(1.0	)%	(3.1	)%
Percentage (warmer) colder than 30-year average	(0.1	)%	0.3	%
Cooling degree-days	894		632		777
Percentage warmer (cooler) than prior year	41.9	%	(16.3	)%
Percentage warmer (cooler) than 30-year average	15.1	%	(18.7	)%

Weather conditions impact electric and, to a greater extent during the winter, gas sales in NSTAR’s service area. The first quarter of 2005 was 2.6% warmer than the same period in 2004, followed by a change to a cooler spring in 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.

Other Events

Impact from Hurricanes

During the summer of 2005, Hurricanes Katrina and Rita impacted natural gas production, processing and transportation assets in the Gulf of Mexico (GOM). None of these facilities are owned by NSTAR; however, NSTAR depends on resources in the GOM for supply of natural gas in addition to storage supplies which were not affected by the storms. One of the facilities impacted is the Tennessee Gas Pipeline (TGP) 500 Line, which is under repair. TGP’s initial assessment is that this pipeline will be out of service for three to six months. NSTAR has approximately 6% of its peak design winter need supplied by the 500 Line. NSTAR has contracted to replace this supply with Canadian supplies. NSTAR is actively involved with other utilities, pipelines, suppliers and regulators in assessing the GOM supplies and will continue to respond as necessary. NSTAR cannot predict the impact GOM may have on supply available during the remainder of this winter heating season.

Energy Prices

It is possible that the recent unprecedented rise in energy prices, resulting from hurricanes Katrina and Rita and global energy conditions, may have a negative impact on electric and gas demand and therefore on NSTAR’s future electric and gas sales. NSTAR can not predict the overall impact resulting from these events on its financial positions, results of operations or cash flows.

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Operating Revenues

Operating revenues for 2005 increased 9.8% from 2004 as follows:

					Increase/(Decrease)
(in millions)	2005		2004		Amount			Percent
Electric revenues
Retail distribution and transmission	$	867.1	$	852.7	$	14.4		1.7
Energy, transition and other		1,666.7		1,480.6		186.1		12.6
Total retail		2,533.8		2,333.3		200.5		8.6
Wholesale		9.7		16.9		(7.2	)	(42.6	)
Total electric revenues		2,543.5		2,350.2		193.3		8.2
Gas revenues
Firm and transportation		147.5		147.7		(0.2	)	(0.1	)
Energy supply and other		423.7		344.6		79.1		23.0
Total gas revenues		571.2		492.3		78.9		16.0
Unregulated operations revenues		128.4		111.8		16.6		14.8
Total operating revenues	$	3,243.1	$	2,954.3	$	288.8		9.8

Electric Revenues

Electric retail distribution revenues primarily represent charges to customers for the Company’s recovery of its capital investment, including a return component, and operation and maintenance related to its electric distribution infrastructure. The transmission revenue component represents charges to customers for the recovery of costs to move the electricity over high voltage lines from the generator to the Company’s substations. The increase in retail distribution and transmission revenues reflects a 2.9% increase in retail mWh sales substantially all in the residential and commercial sector and includes an increase in demand revenues from NSTAR’s commercial customers.

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

Energy, transition and other revenues primarily represent charges to customers for the recovery of costs incurred by the Company in order to acquire the energy supply on their behalf (basic service) and a transition charge for recovery of the Company’s prior investments in generating plants and the costs related to long-term power contracts. Energy supply contract prices vary among the NSTAR Electric companies. However, the retail revenues related to basic service are fully reconciled to the costs incurred and have no impact on NSTAR’s consolidated net income. Furthermore, transition revenues are fully reconciled with the cost currently recognized by the Company and, as a result, do not have an effect on the Company’s earnings. Other revenues primarily relate to the Company’s ability to effectively reduce stranded costs (mitigation incentive), rental revenue from electric property and annual cost reconciliation true-up adjustments. In 2004, the cost reconciliation true-up adjustments increased revenues by approximately $4.7 million. The $186.1 million increase in energy, transition and other revenues is primarily attributable to energy procurement costs and approximately $12.2 million of MDTE-approved incentive revenue entitlements for successfully lowering transition charges resulting from the securitization financing that closed on March 1, 2005. In addition, NSTAR Electric is permitted to earn a carrying charge on transition deferral balances.

Wholesale revenues relate to electric sales to municipal utilities and certain other governmental authorities. The decrease in 2005 wholesale revenues reflects the expiration of a municipal wholesale power supply contract in

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the fourth quarter of 2004 that was not renewed and a wholesale power supply contract with a regional airport that expired on October 31, 2005. As of November 1, 2005, NSTAR no longer has wholesale electric supply contracts. Amounts collected from wholesale customers are credited to retail customers through the transition charge. Therefore, the expiration of these wholesale supply contracts had no material impact on results of operations or cash flows.

Gas Revenues

Firm and transportation gas revenues primarily represent charges to customers for NSTAR Gas’ recovery of costs of its capital investment in its gas infrastructure, including a return component, and for the recovery of costs for the ongoing operation and maintenance of that infrastructure. The transportation revenue component represents charges to customers for the recovery of costs to move the natural gas over pipelines from gas suppliers to take stations located within NSTAR Gas’ service area. The impact of warmer winter weather conditions, energy efficiency and conservation efforts and customers switching to alternate fuel sources as a result of energy price concerns, resulted in the decrease in sales volumes of 3.1% during 2005. Firm gas and transportation revenues were nearly unchanged when compared with the prior year.

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

Energy supply and other gas revenues primarily represent charges to customers for the recovery of costs to acquire the natural gas in the marketplace and a charge for recovery gas supplier service costs. The energy supply and other revenue increase of $79.1 million primarily reflects the impact of the higher cost of gas purchased from these suppliers. These revenues are fully reconciled with the cost currently recognized by the Company and, as a result do not have an effect on the Company’s earnings.

Unregulated Operations Revenues

Unregulated operating revenues are primarily derived from NSTAR’s unregulated businesses that include district energy operations and telecommunications. Unregulated revenues were $128.4 million in 2005 compared to $111.8 million in 2004, an increase of $16.6 million, or 14.8%. The increase in unregulated revenues is primarily the result of higher steam sales volume and higher electric sales and prices to its Advanced Energy Systems, Inc. Medical Area Total Energy Plant (MATEP) customers. Partially offsetting these revenues was the sale of a portion of NSTAR’s district energy steam assets in September 2005. Refer to the “Sale of Properties” contained within this MD&A section.

Operating Expenses

Purchased power costs were $1,428.4 million for 2005 compared to $1,347.8 million for 2004, an increase of $80.6 million, or 6%. The increase is primarily the result of the higher energy procurement costs of both our regulated and unregulated companies and increased sales. NSTAR Electric adjusts its rates to collect the costs related to energy supply from customers on a fully reconciling basis. Due to this rate adjustment mechanism, changes in the amount of energy supply expense have no impact on earnings.

Cost of gas sold, representing NSTAR Gas’ supply expense, was $388.4 million for 2005 compared to $313.3 million in 2004, an increase of $75.1 million, or 24%. Despite a 3.1% decline in firm gas sales, the expense increase reflects the higher costs of gas supply. NSTAR Gas maintains a flexible resource portfolio consisting of gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services. NSTAR Gas adjusts its rates to collect costs related to gas supply from customers on a fully reconciling basis.

Operations and maintenance expense was $452.6 million in 2005 compared to $421.4 million in 2004, an increase of $31.2 million, or 7%. This increase primarily reflects costs associated with storms (approximately $8.6 million), facilities consolidation (approximately $3 million), incremental costs associated with a work

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stoppage by union employees (approximately $3 million), a net increase to an environmental cost due to a settlement of an environmental claim and an increase in insurance costs (approximately $6.2 million and $2.5 million, respectively), higher bad debt expense (approximately $6.9 million) and higher employee expenses.

Depreciation and amortization expense was $336.7 million in 2005 compared to $254.9 million in 2004, an increase of $81.8 million or 32%. The increase primarily reflects amortization costs related to transition property regulatory asset ($145.4 million and $70.9 million in 2005 and 2004, respectively) and higher depreciable distribution and transmission plant in service.

DSM and renewable energy programs expense was $68.4 million in 2005 compared to $67.3 million in 2004, an increase of $1.1 million, or 2%, which are consistent with the collection of conservation and renewable energy revenues. These costs are in accordance with program guidelines established by the MDTE and are collected from customers on a fully reconciling basis plus a small incentive return.

Property and other taxes were $102.4 million in 2005 compared to $103.1 million in 2004, a decrease of $0.7 million, or less than 1%.

Income tax expenseattributable to operations were $110.7 million in 2005 compared to $108.3 million in 2004, an increase of $2.4 million, or 2%, primarily reflecting the increase in tax expense resulting from a higher level of taxable income. Offsetting this increase was the recognition of a favorable resolution of uncertain tax positions that decreased tax expense by $4.2 million.

Other income, net

Other income, net was approximately $12.1 million in 2005 compared to $7.3 million in 2004, an increase of $4.8 million. The increase is primarily due to a $2.5 million gain recognized in 2005 from the sale of a portion of NSTAR’s district energy steam assets, recognition of tax benefits resulting from the realization of capital tax gains from sales of property ($4.7 million), offset by the absence in 2005 of proceeds from an executive life insurance policy of $1.2 million and $1 million in employee-related contract fees as a result of the Blackstone Station sale in 2004.

Other deductions, net

Other deductions, net were approximately $2 million in 2005 compared to $1.5 million in 2004. The $0.5 million increase was due to slightly higher charitable donations expenses and higher non-intercompany expenses billed from NSTAR’s services company.

Interest charges

Interest on long-term debt and transition property securitization certificateswas $165.7 million in 2005 compared to $147.3 million in 2004, an increase of $18.4 million, or 12%. 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 $17.5 million associated with transition property securitization. Securitization interest represents interest on securitization certificates of BEC Funding, BEC Funding II and CEC Funding collateralized by the future income stream associated primarily with NSTAR’s stranded costs. The future income stream was sold to these companies by Boston Edison and ComElectric.

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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

• The impact of the March 1, 2005 retirement of $150 million variable rate Note, due in May 2006, at ComElectric with a portion of the proceeds from the sale of CEC Funding LLC’s securitization certificates

Short-term and other interest expensewas $5.6 million in 2005 compared to $7.4 million in 2004, a decrease of $1.8 million, or 24%. The decrease is primarily due to lower interest costs of $3.8 million on regulatory deferrals offset by higher short-term debt borrowing costs of $4.8 million primarily reflective of a 199 basis point increase in 2005 weighted average borrowing rates and a higher average level of funds borrowed as compared to 2004. The weighted average short-term interest rates including fees were 3.81% and 1.82% in 2005 and 2004, respectively. The higher rate of borrowing during 2005 includes $117 million in contributions to NSTAR’s postretirement benefit plans and $100 million for the retirement of Boston Edison’s Floating Rate Debentures in October 2005.

Allowance for funds used during construction (AFUDC)increased $2.7 million in 2005 primarily due to higher levels of construction activity primarily related to the on-going construction of NSTAR’s 345 kV transmission line.

2004 compared to 2003

Executive Summary

Earnings per common share were as follows:

	Years ended December 31,
	2004		2003		% Change
Basic	$	1.77	$	1.71	3.5
Diluted	$	1.76	$	1.70	3.5

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

NSTAR in 2004 generated $429.4 million of cash from operations sufficient to fund approximately $313.4 million of net capital expenditures, and $119.8 million of cash dividends. The Company’s plant expenditures contributed to NSTAR’s increased operational performance in reliability, restoration, and customer service measurements. Favorable market conditions and the Company’s strong credit ratings contributed to the Company’s 2004 refinancing activities. These financing activities included the retirement of $181 million of 7.80% series of Debentures in March 2004 and a reduction in short-term borrowings of $77.7 million from year-end 2003. This retirement was temporarily funded with short-term borrowings, which were subsequently paid down with the proceeds from the issuance of a 10-year, $300 million 4.875% series of Debentures, which was completed in April 2004.

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Energy Sales

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

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

Weather Conditions

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

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

	2004		2003		Normal 30-Year Average
Heating degree-days	6,500		6,710		6,482
Percentage (warmer) colder than prior year	(3.1	)%	10.5	%
Percentage (warmer) colder than 30-year average	0.3	%	2.6	%
Cooling degree-days	632		755		777
Percentage (cooler) than prior year	(16.3	)%	(22.3	)%
Percentage (cooler) than 30-year average	(18.7	)%	(2.8	)%

Weather conditions impact electric and, to a greater extent during the winter, gas sales in NSTAR’s service area. Despite a very cold January, the first quarter of 2004 was 2.4% warmer than the same period in 2003, followed by continued warmer temperatures for the second quarter. The cooler than prior year third quarter resulted in reduced air conditioning demand that preceded a slightly colder fourth quarter of 2004. The comparative information above relates to heating and cooling degree-days for 2004 and 2003 and the number of degree-days

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in a “normal” year as represented by a 30-year average. A “degree-day” is a unit measuring how much the outdoor mean temperature falls below (heating degree-day) or rises above (cooling degree-day) a base of 65 degrees. Each degree below or above the base temperature is measured as one degree-day.

Operating Revenues

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

					Increase/(Decrease)
(in millions)	2004		2003		Amount			Percent
Electric revenues
Retail distribution and transmission	$	852.7	$	860.7	$	(8.0	)	(0.9	)
Energy, transition and other		1,480.6		1,451.1		29.5		2.0
Total retail		2,333.3		2,311.8		21.5		0.9
Wholesale		16.9		21.5		(4.6	)	(21.4	)
Total electric revenues		2,350.2		2,333.3		16.9		0.7
Gas revenues
Firm and transportation		147.7		149.4		(1.7	)	(1.1	)
Energy supply and other		344.6		315.8		28.8		9.1
Total gas revenues		492.3		465.2		27.1		5.8
Unregulated operations revenues		111.8		113.2		(1.4	)	(1.2	)
Total operating revenues	$	2,954.3	$	2,911.7	$	42.6		1.5

Electric Revenues

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

Energy, transition and other revenues primarily represent charges to customers for the recovery of costs incurred by the Company in order to acquire the energy supply on behalf of its customers and a transition charge for recovery of the Company’s prior investments in generating plants and the costs related to long-term power contracts. The energy revenues relate to customers being provided energy supply under either standard offer or default service. Other revenues primarily relate to the Company’s ability to effectively reduce stranded costs (mitigation incentive), rental revenue from electric property and annual cost reconciliation true-up adjustments. In 2004, the cost reconciliation true-up adjustments increased revenues by approximately $4.7 million. The $29.5 million increase in energy, transition and other revenues is primarily attributable to higher rates for default service and standard offer service, which include ComElectric and Cambridge Electric standard offer service fuel index adjustments throughout 2004 and for Boston Edison in the fourth quarter of 2004.

Wholesale revenues relate to services provided to municipalities and certain other governmental authorities. This decrease in 2004 wholesale revenues reflects the expiration of two wholesale power supply contracts in 2003 and one contract in 2004. As of November 1, 2005, NSTAR no longer has wholesale electric supply contracts. Amounts collected from wholesale customers were previously credited to retail customers through the transition charge. Therefore, the expiration of these contracts had no impact on results of operations.

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Gas Revenues

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

Energy supply and other gas revenues primarily represent charges to customers for the recovery of costs to the Company in order to acquire the natural gas in the marketplace and a charge for recovery of the Company’s gas supplier service costs. The revenue increase of $28.8 million primarily reflects the impact of the higher cost of gas sold that reflected a weighted average cost of gas per therm increase over the same period in 2003 of approximately 5.3%. These revenues are fully reconciled with the cost currently recognized by the Company and, as a result, do not have an effect on the Company’s earnings.

Unregulated Operations Revenues

Unregulated operations revenues are primarily derived from NSTAR’s businesses that include district energy operations and telecommunications. Unregulated revenues were $111.8 million in 2004 compared to $113.2 million in 2003, a decrease of $1.4 million, or 1%. The decrease is primarily the result of the sale of Blackstone Station to Harvard University in April 2003 partially offset by an increase in the revenues from electric and chilled water services and higher steam revenues resulting from colder weather and higher fuel costs.

Operating Expenses

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

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

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

Depreciation and amortization expensewas $254.8 million in 2004 compared to $243.4 million in 2003, an increase of $11.4 million or 5%. The increase primarily reflects higher depreciable distribution and transmission plant in service, an increase to the transmission depreciation rate, and increased expense related to software and merger costs to achieve amortization.

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

Property and other taxeswere $103.1 million in 2004 compared to $97.8 million in 2003, an increase of $5.3 million, or 5%. This increase was due to higher overall municipal property taxes of $5.1 million caused primarily by higher assessments. Higher property taxes are primarily due to increased plant investment and increased rates associated with legislation passed in Massachusetts allowing for the temporary shift of property tax burdens from residential to commercial property owners, in particular, in the City of Boston.

Income tax expenseattributable to operations were $108.3 million in 2004 compared to $113.5 million in 2003, a decrease of $5.2 million, or 5%. Despite higher pre-tax income in 2004, incomes taxes decreased due to the reversal of state tax reserves as a result of resolution of prior audit periods and permanent tax benefits related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The tax benefit related to the Act will not impact NSTAR’s results of operations as these tax benefits are incorporated into the Company’s pension and PBOP rate adjustment mechanism.

Other income, net

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

Other deductions, net

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

Interest charges

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

Short-term and other interest expensewas $7.4 million in 2004 compared to $8.0 in 2003, a decrease of $0.6 million, or 8%. The decrease in short-term and other interest expense primarily relates to a reduction in bank service fees and other charges ($1.9 million) resulting from a reduction in the level of NSTAR’s revolving line of credit. In

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addition, the decrease in short-term and other expenses includes a lower average level of debt outstanding of $164.9 million as compared to $234.8 million for 2004 and 2003, respectively, slightly offset by higher bank borrowing rates. The weighted average short-term interest rates including fees were 1.82% and 1.68% in 2004 and 2003, respectively. Taken together, these factors decreased short-term borrowing costs by $0.6 million. Offsetting these decreases was an increase in regulatory interest due to higher customer deferral balances.

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

Liquidity, Commitments and Capital Resources

The major factor that effects NSTAR’s cash requirements is the level of plant expenditures. Plant expenditures currently forecasted for 2006 are $408 million. The plant expenditure level over the following four years (2007-2010) is currently forecasted to aggregate to approximately $1.2 billion.

Forecasted plant expenditures in 2006 include remaining costs of $89 million for NSTAR’s 345kV transmission project that is expected to total $220 million.

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

(in millions)	2006		2007		2008		2009		2010		Years Thereafter		Total
Long-term debt	$	28	$	15	$	17	$	7	$	633	$	952	$	1,652
Interest obligation on long-term debt		109		107		105		104		79		258		762
Transition property securitization		95		151		153		153		119		212		883
Interest obligation on transition property securitization		45		37		30		21		13		14		160
Leases		20		16		15		13		11		36		111
Electric capacity obligations		2		2		2		2		3		21		32
Gas contractual obligations		48		48		47		45		44		67		299
Purchase power buy-out obligations		156		160		162		142		140		206		966
	$	503	$	536	$	531	$	487	$	1,042	$	1,766	$	4,865

Transition property securitization payments reflects securities issued in 1999 by BEC Funding LLC, a subsidiary of Boston Edison and on March 1, 2005, additional transition property securitization bonds issued through BEC Funding II, LLC, a subsidiary of Boston Edison and CEC Funding, LLC, a subsidiary of ComElectric. BEC Funding LLC, BEC Funding, II, LLC and CEC Funding, LLC recover the principal and interest obligations for their transition property securitization bonds from customers of Boston Edison and ComElectric, respectively, through a component of Boston Edison’s and ComElectric’s transition charges and, as a result, these payment obligations do not affect NSTAR’s overall cash flow.

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

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Current Cash Flow Activity

NSTAR’s primary uses of cash in 2005 included capital expenditures, dividend payments, debt reductions, and liquidation payments under certain purchase power contract buy-out agreements.

Net operating cash flow used in 2005 was $26.9 million and reflects the impact of its obligations related to the purchase power contract buy-outs in 2005. The Company used $370.5 million in its investing activities that consisted of $383.6 million of plant expenditures, which included construction costs related to NSTAR Electric’s 345 kV project and other system reliability and infrastructure improvement projects incurred by NSTAR Electric and NSTAR Gas operations. Additionally, the Company provided $400.5 million (net) from financing activities primarily from the issuance of $674.5 million of transition property securitization certificates used to finance its purchase power contract termination payments.

Operating Activities

The net cash used in 2005 operating activities was significantly impacted by the contract termination payments on certain purchase power contracts in 2005. The payments of approximately $653.2 million created a current tax deduction. As a result, income tax payments were $38.9 million lower in 2005 than in 2004. These tax benefits represent a book/tax timing difference which will reverse as amounts are collected from customers.

Other changes to NSTAR’s working capital primarily reflect the timing of ordinary receipts and disbursements. For 2005 and 2004, NSTAR contributed approximately $117.6 million and $62.7 million, respectively, to its retirement benefit plans.

In 2004 and 2003, NSTAR benefited from bonus depreciation for income tax purposes (between 30% and 50% depreciation on new capital additions). As a result, NSTAR’s deferred income taxes have increased. As of December 31, 2004, the bonus depreciation rules have generally expired. Therefore, in 2005 and beyond, the cash flow benefit from bonus depreciation will be limited to certain qualified projects and NSTAR does not anticipate realizing any further benefit from bonus depreciation.

Investing Activities

The net cash used in investing activities in 2005 of $370.5 million consists primarily of capital expenditures related to infrastructure investments in transmission and distribution systems. Capital expenditures increased $70.2 million from the prior year primarily due to Boston Edison’s 345 kV project. Boston Edison spent nearly $120 million on this project in 2005.

Financing Activities

The net cash provided by financing activities in 2005 of $400.5 million primarily reflects the issuance of $674.5 million of transition property securitization certificates on March 1, 2005 and additional borrowing from short-term debt of $256.1 million. Offsetting the receipt of cash from the securitization financing, NSTAR used cash to make long-term debt redemptions and sinking funds payments of $400.8 million and to pay dividends of $125.7 million.

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

In connection with the NSTAR Dividend Reinvestment and Direct Common Shares Purchase Plan, NSTAR has issued approximately 258,000 shares under this registration and received approximately $7.1 million in 2005.

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Short-Term Financing Activities

NSTAR’s short-term debt increased by $256.1 million to $417.5 million at December 31, 2005 as compared to $161.4 million at December 31, 2004. The increase resulted primarily from additional working capital needs that reflected the significant increase in contributions to NSTAR’s pension and postretirement benefit plans and the financing of the retirement, at maturity, of Boston Edison’s $100 million Variable Rate notes on October 17, 2005.

Long-Term Financing Activities

On March 1, 2005, two wholly owned special purpose subsidiaries, BEC Funding II, LLC and CEC Funding LLC, issued $265.5 million and $409 million, respectively, in notes to a special purpose trust created by two Massachusetts state agencies. The trust then concurrently issued a total of $674.5 million of rate reduction certificates to the public. These certificates represent fractional, undivided beneficial interests in the notes issued by BEC Funding II, LLC and CEC Funding, LLC and are secured by a portion of the transition charge assessed on Boston Edison’s and ComElectric’s retail customers as permitted under the 1997 Massachusetts Electric Industry Restructuring Act and authorized by the MDTE. These certificates are non-recourse to Boston Edison and ComElectric, respectively. The assets and revenues of BEC Funding II, LLC and CEC Funding, LLC, including without limitation, the transition property, are owned solely by BEC Funding II, LLC and CEC Funding, LLC, and are not available to creditors of Boston Edison, ComElectric or NSTAR. The certificates and the related BEC Funding II, LLC and CEC Funding, LLC notes were issued at a weighted average yield of 4.15% in four classes with varying final maturity dates between 2008 and 2015. Scheduled semi-annual principal payments began in September 2005. The net proceeds from this transaction were used to make liquidation payments required in connection with the termination of certain purchase power agreements, and, in the case of ComElectric, to repay outstanding debt.

In 2004, NSTAR Electric executed agreements to buy-out or restructure twelve of its purchase power agreements subject to MDTE approval. These agreements constituted approximately 685 MW of the remaining 800 MW of purchased power commitments, and reduced the amount of above-market energy costs that NSTAR Electric will incur and collect from its customers through its transition charges. As of December 31, 2004, four of these agreements received MDTE approval and were recognized. Two of the four agreements require NSTAR Electric to make monthly payments through December 2008 totaling approximately $80 million. The other two agreements require NSTAR Electric to make monthly payments through September 2011 totaling approximately $125 million. These buy-out/restructuring agreements, once completed, provide no economic benefit to NSTAR Electric and, therefore, the agreements’ contract termination costs were recorded on the accompanying Consolidated Financial Statements.

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

The total amount recognized as of December 31, 2005 and 2004 for obligations relating to eight of the twelve contracts is approximately $764 million and $852 million (present valued); approximately $156 million and $145 million are reflected as a component of current liabilities - energy contracts and approximately $608 million and $707 million as a component of Deferred credits - energy contracts on the accompanying Consolidated Balance Sheets as of December 31, 2005 and 2004, respectively. NSTAR Electric has recorded a corresponding regulatory asset to reflect the full future recovery of these payments through its transition charge. This recognition represents a non-cash increase to assets and liabilities.

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Also in January 2005, the MDTE approved the remaining four contract buy-outs with two suppliers that reduced the overall amount of transition costs to be paid for above-market contracts. These contracts are buy-out arrangements whereby NSTAR Electric has made contract termination payments in full release of its obligation under the purchase power agreements. On August 31, 2004, NSTAR Electric filed with the MDTE a proposed financing plan that sought approval for full recovery of these buy-out costs and the issuance of $674.5 million of transition property securitization bonds to provide the funds for these buy-out agreements. The MDTE approved the financing plan in January 2005. On February 15, 2005, the bonds were priced at a weighted average yield of 4.15% and the securitization financing closed on March 1, 2005.

Management continuously reviews its capital expenditure and financing programs. These programs and, therefore, the forecasts included in NSTAR’s 2005 Form 10-K are subject to revision due to changes in regulatory requirements, operating requirements, environmental standards, availability and cost of capital, interest rates and other assumptions.

Sources of Additional Capital and Financial Covenant Requirements

With the exception of the indemnity agreement, referenced in “Financial and Performance Guarantees” within this MD&A, NSTAR has no financial guarantees, commitments, debt or lease agreements that would require a change in terms and conditions, such as acceleration of payment obligations, as a result of a change in its credit rating. However, NSTAR’s subsidiaries could be required to provide additional security for power supply contract performance, such as a letter of credit for their pro-rata share of the remaining value of such contracts. Refer to “Performance Assurances from Electricity and Gas Supply Agreements” and “Financial and Performance Guarantees” as disclosed in this MD&A.

NSTAR and Boston Edison have no financial covenant requirements under their respective long-term debt arrangements. ComElectric, Cambridge Electric and NSTAR Gas have financial covenant requirements under their long-term debt arrangements and were in compliance at December 31, 2005 and 2004. NSTAR’s long-term debt other than the Mortgage Bonds, Notes of NSTAR Gas and of MATEP, a wholly owned subsidiary of NSTAR, is unsecured.

NSTAR has executed a five-year, $175 million revolving credit agreement that expires in November 2009. At December 31, 2005 and 2004, there were no amounts outstanding under the revolving credit agreement. This credit facility serves as a backup to NSTAR’s $175 million commercial paper program that, at December 31, 2005 and 2004, had $66 million and $5 million outstanding, respectively. Under the terms of the credit agreement, NSTAR is required to maintain a maximum total consolidated debt to total capitalization ratio of not greater than 65% at all times, excluding Transition Property Securitization Certificates, and excluding Accumulated other comprehensive income (loss) from common equity. Commitment fees must be paid on the total agreement amount. At December 31, 2005 and 2004, NSTAR was in full compliance with the aforementioned covenant as the ratios were 56.7% and 58.3% respectively.

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.

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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.

As of December 31, 2005, ComElectric, Cambridge Electric and NSTAR Gas, collectively, have $245 million available under several lines of credit and had $154.5 million and $109.9 million outstanding under these lines of credit at December 31, 2005 and 2004, respectively. As of September 28, 2004, ComElectric and Cambridge Electric have FERC authorization to issue short-term debt securities from time-to-time on or before November 30, 2006 and June 27, 2006, with maturity dates no later than November 30, 2007 and June 27, 2007, respectively, in amounts such that the aggregate principal does not exceed $125 million and $60 million, respectively, at any one time. NSTAR Gas is not required to seek approval from FERC to issue short-term debt.

On June 30, 2004, NSTAR filed an S-3 Registration Statement with the SEC for the purpose of registering two million common shares in connection with the NSTAR Dividend Reinvestment and Direct Common Shares Purchase Plan. The Registration Statement became effective on July 29, 2004. Since the effective date, NSTAR has issued approximately 312,000 and 258,000 shares under this registration and received approximately $7.6 million and $7.1 million in 2004 and 2005, respectively. Additionally, NSTAR issued approximately 172,000 shares as part of its Share Incentive Plan. No cash was received from this issuance.

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

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

Performance Assurances from Electricity and Gas Supply Agreements

NSTAR Electric 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. NSTAR Electric 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 but could change as a result of NSTAR’s recently approved rate Settlement Agreement. NSTAR Electric currently is recovering payments it is making to suppliers from its customers. Most of NSTAR Electric’s power suppliers are either investment grade companies or are subsidiaries of larger companies with investment grade or better credit ratings. In accordance with NSTAR’s Internal Credit Policy, and to minimize NSTAR Electric risk in the event the supplier encounters financial difficulties or otherwise fails to perform, NSTAR has financial assurances and guarantees that include both parental guarantees and letters of credit in place from the parent company of the supplier. In addition, under these agreements, in the event that the supplier (or its parent guarantor) fails to maintain an investment grade credit rating, it is required to provide additional security for performance of its obligations. In view of current volatility in the energy supply industry, NSTAR Electric is unable to determine whether its suppliers (or their parent guarantors) will become subject to financial difficulties, or whether these financial assurances and guarantees are sufficient. In the event the supplier (or its guarantor) does not provide the required additional security within the required time frames, NSTAR Electric may then terminate the agreement. In such event, NSTAR may be required to secure alternative sources of supply at higher or lower prices than provided under the

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terminated agreements. Some of these agreements include a reciprocal provision, where in the event that an NSTAR Electric distribution company receives a downgrade, that company could be required to provide additional security for performance, such as a letter of credit. Additionally, the hedging agreements that NSTAR Gas enters into related to its gas purchases have a termination clause for either party in the event the credit rating of the other falls below a stipulated level.

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

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

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

Financial and Performance Guarantees

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

At December 31, 2005, outstanding guarantees totaled $38.1 million as follows:

(in thousands)
Letters of Credit	$	13,100
Surety Bonds		16,200
Other Guarantees		8,800
Total Guarantees	$	38,100

Letters of Credit

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. NSTAR believes that it is very unlikely that a draw will be made on the standby letter of credit. In addition, NSTAR issued a $5.6 million letter of credit for the benefit of a third party, as trustee in connection with the 6.924% Notes of one of its subsidiaries. The letter of credit is available if the subsidiary has insufficient funds to pay the debt service requirements. As of December 31, 2005, there have been no amounts drawn under these letters of credit.

Surety Bonds

As of December 31, 2005, certain of NSTAR’s subsidiaries have purchased a total of $1.5 million of performance surety bonds for the purpose of obtaining licenses, permits and rights-of-way in various municipalities. In addition, NSTAR and certain of its subsidiaries have purchased approximately $14.7 million in

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workers’ compensation self-insurer bonds. These bonds support the guarantee by NSTAR and certain of its subsidiaries to the Commonwealth of Massachusetts required as part of the Company’s workers’ compensation self-insurance program. On January 3, 2006, NSTAR and certain of its subsidiaries executed indemnity agreements to provide additional financial security to its bond company in the form of a contingent letter of credit to be triggered in the event of a downgrade in the future of NSTAR’s Senior Note rating to below BBB by S&P and/or to below Baa1 by Moody’s. These Indemnity Agreements cover both the performance surety bonds and workers’ compensation bonds.

Other

NSTAR and its subsidiaries have also issued $8.8 million of residual value guarantees related to its equity interest in the Hydro-Quebec transmission companies.

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

Contingencies

Environmental Matters

NSTAR subsidiaries face possible liabilities as a result of involvement in several multi-party disposal sites, state-regulated sites or third party claims associated with contamination remediation. NSTAR 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 February 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, NSTAR had reserves of $10.3 million and $3.9 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 NSTAR’s results of operation, cash flows or its financial position.

NSTAR Gas is participating in the assessment or remediation of certain former manufactured gas plant (MGP) sites and alleged MGP waste disposal locations to determine if and to what extent such sites have been contaminated and whether NSTAR Gas may be responsible for remedial action. The MDTE has approved recovery of costs associated with MGP sites over a 7-year period, without carrying costs. As of December 31, 2005 and 2004, NSTAR recorded a liability of approximately $3.6 million and $3.8 million, respectively, as estimates for site cleanup costs for several MGP sites for which NSTAR Gas was previously cited as a potentially responsible party. A corresponding regulatory asset was recorded that reflects the future rate recovery for these costs.

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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 NSTAR’s responsibilities for such sites evolve or are resolved. NSTAR’s ultimate liability for future environmental remediation costs may vary from these estimates. Based on NSTAR’s current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, NSTAR does not believe that these environmental remediation costs will have a material adverse effect on NSTAR’s consolidated financial position, results of operations or cash flows.

Capital Spending Commitments

In the second quarter of 2005, NSTAR began construction of a switching station in Stoughton, Massachusetts and a 345kV transmission line that will connect the switching station to South Boston. As of December 31, 2005, construction that is part of this project is also in progress on the expansion of two existing substations. 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. This project is expected to be placed in service during the summer of 2006. A substantial portion of the cost of this project will be shared by other utilities in New England based on ISO-New England’s approval and will be recovered by NSTAR through wholesale and retail transmission rates. As of December 31, 2005, NSTAR has contractual construction cost commitments of approximately $17 million related to this project.

Employees and Employee Relations

As of December 31, 2005, NSTAR had approximately 3,050 employees, including approximately 2,150, or 70%, who are represented by three 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. Approximately 60 employees of Advanced Energy Systems’ MATEP subsidiary are represented by Local 877, the International Union of Operating Engineers, AFL-CIO, under a contract that expires on September 30, 2006.

Management believes it has satisfactory relations with its employees.

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
(in thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term indebtedness (including current maturities)	$	2,525,517	$	2,642,190	$	2,250,647	$	2,483,220

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

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

However, NSTAR’s exposure to financial market risk results primarily from fluctuations in interest rates. NSTAR is exposed to changes in interest rates primarily based on levels of short-term debt outstanding. The weighted average interest rates for long-term indebtedness, including current maturities were 6.03% and 6.23% in 2005 and 2004, respectively.

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Item 8. Financial Statements and Supplementary Data

NSTAR

Consolidated Statements of Income

	Years ended December 31,
	2005			2004			2003
	(in thousands, except earnings per share)
Operating revenues	$	3,243,120		$	2,954,332		$	2,911,711
Operating expenses:
Purchased power and cost of gas sold		1,816,765			1,661,100			1,614,290
Operations and maintenance		452,558			421,367			443,931
Depreciation and amortization		336,670			254,852			243,424
Demand side management and renewable energy programs		68,441			67,294			66,217
Property and other taxes		102,426			103,061			97,837
Income taxes		110,690			108,330			113,501
Total operating expenses		2,887,550			2,616,004			2,579,200
Operating income		355,570			338,328			332,511
Other income (deductions):
Write-down of RCN investment, net		—			—			(4,450	)
Other income, net		12,120			7,305			14,397
Other deductions, net		(2,032	)		(1,487	)		(1,712	)
Total other income, net		10,088			5,818			8,235
Interest charges:
Long-term debt		119,970			119,164			121,027
Transition property securitization		45,694			28,150			32,715
Short-term debt and other		5,608			7,394			8,043
Allowance for borrowed funds used during construction and capitalized interest		(3,709	)		(1,003	)		(4,573	)
Total interest charges		167,563			153,705			157,212
Preferred stock dividends of subsidiary		1,960			1,960			1,960
Net income	$	196,135		$	188,481		$	181,574
Weighted average common shares outstanding:
Basic		106,756			106,268			106,065
Diluted		107,100			107,292			106,797
Earnings per common share (Note K):
Basic	$	1.84		$	1.77		$	1.71
Diluted	$	1.83		$	1.76		$	1.70

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

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NSTAR

Consolidated Statements of Comprehensive Income

	Years ended December 31,
	2005			2004			2003
	(in thousands)
Net income	$	196,135		$	188,481		$	181,574
Other comprehensive income, net:
Unrealized gain (loss) on investments		—			—			2,783
Reclassification adjustment for (gain) loss included in net income		—			—			(2,783	)
Additional minimum pension liability		(5,132	)		(5,817	)		1,104
Deferred income taxes (benefit)		2,113			2,414			(389	)
Comprehensive income	$	193,116		$	185,078		$	182,289

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

NSTAR

Consolidated Statements of Retained Earnings

	Years ended December 31,
	2005		2004		2003
	(in thousands)
Balance at the beginning of the year	$	518,252	$	449,114	$	382,886
Add:
Net income		196,135		188,481		181,574
Subtotal		714,387		637,595		564,460
Deduct:
Dividends declared:
Common shares*		92,887		119,343		115,346
Balance at the end of the year	$	621,500	$	518,252	$	449,114

* As a result of a change in NSTAR’s Board of Trustee meetings schedule in 2005, the fourth quarter dividend typically declared in December was approved on January 26, 2006. The dividend payment schedule remains unchanged.

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

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NSTAR

Consolidated Balance Sheets

	December 31,
	2005					2004
Assets	(in thousands)
Utility plant in service, at original cost	$	4,454,774				$	4,454,774
Less: accumulated depreciation		1,178,259			3,492,800		1,122,810			3,331,964
Construction work in progress					208,957					103,866
Net utility plant					3,701,757					3,435,830
Non-utility property, net					138,222					144,148
Equity investments					13,705					13,887
Other investments					63,441					59,096
Current assets:
Cash and cash equivalents		15,612					12,497
Restricted cash		14,282					10,254
Accounts receivable, net of allowance of $24,504 and $21,804, respectively		305,441					302,194
Accrued unbilled revenues		59,400					53,752
Regulatory assets		446,286					300,238
Inventory, at average cost		120,924					86,397
Income taxes		57,444					21,063
Other		16,894			1,036,283		11,434			797,829
Deferred debits:
Regulatory assets - energy contracts					683,193					1,269,651
Regulatory asset - goodwill					658,538					678,698
Regulatory assets - other					924,693					607,037
Prepaid pension					346,889					297,746
Other					78,843					87,434
Total assets				$	7,645,564				$	7,391,356
Capitalization and Liabilities
Common equity:
Common shares, par value $1 per share, 200,000,000 shares authorized; 106,808,376 shares in 2005 and 106,550,282 shares in 2004 issued and outstanding	$	106,808				$	106,550
Premium on common shares		813,099					819,454
Retained earnings		621,500					518,252
Accumulated other comprehensive loss		(6,392	)		1,535,015		(3,374	)		1,440,882
Cumulative non-mandatory redeemable preferred stock of subsidiary					43,000					43,000
Long-term debt					1,614,411					1,792,654
Transition property securitization					787,966					308,748
Current liabilities:
Long-term debt		28,457					108,197
Transition property securitization		94,683					41,048
Notes payable		417,500					161,400
Deferred income taxes		7,232					8,072
Accounts payable		320,960					239,613
Energy contracts		183,674					171,312
Accrued interest		33,114					33,073
Dividends payable		327					31,227
Accrued expenses		20,729					30,654
Other		62,769			1,169,445		73,346			897,942
Deferred credits:
Accumulated deferred income taxes and unamortized investment tax credits					1,273,456					1,114,588
Energy contracts					683,193					1,269,651
Pension liability					37,351					31,296
Regulatory liability - cost of removal					258,782					258,722
Other					242,945					233,873
Commitments and contingencies
Total capitalization and liabilities				$	7,645,564				$	7,391,356

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

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NSTAR

Consolidated Statements of Cash Flows

	Years ended December 31,
	2005			2004			2003
	(in thousands)
Operating activities:
Net income	$	196,135		$	188,481		$	181,574
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		337,887			254,271			244,244
Deferred income taxes		158,914			71,662			120,471
Gain on sale of steam assets		(2,500	)		—			—
Loss on write-down of RCN investment		—			—			6,146
Allowance for borrowed funds used during construction/capitalized interest		(3,709	)		(1,003	)		(4,573	)
Net changes in:
Accounts receivable and accrued unbilled revenues		(8,895	)		(3,572	)		(6,526	)
Inventory, at average cost		(34,527	)		(6,812	)		(21,188	)
Other current assets		(187,986	)		(131,711	)		(24,286	)
Accounts payable		55,523			8,014			10,536
Other current liabilities		(8,939	)		139,229			(1,382	)
Effects of purchase power contract buyouts		(653,210	)		(8,935	)		(12,741	)
Deferred debits and credits		144,252			(279,789	)		(83,781	)
Decrease in regulatory asset - pension		—			297,746			—
Net change from other miscellaneous operating activities		(19,831	)		(98,172	)		(3,970	)
Net cash (used in) provided by operating activities		(26,886	)		429,409			404,524
Investing activities:
Plant expenditures (excluding AFUDC/capitalized interest)		(383,556	)		(313,387	)		(307,655	)
(Increase) decrease in restricted cash		(4,028	)		2,890			20,755
Proceeds from sale of property, net		16,321			14,252			17,572
Investments		728			1,070			669
Net cash used in investing activities		(370,535	)		(295,175	)		(268,659	)
Financing activities:
Long-term debt redemptions		(400,847	)		(258,357	)		(242,357	)
Debt issue costs		(6,513	)		(1,851	)		(663	)
Issuance of transition property securitization		674,500			—			—
Issuance of long-term debt		—			300,000			150,000
Net change in notes payable		256,100			(77,700	)		40,500
Change in disbursement accounts		(4,103	)		11,922			(3,747	)
Common stock issuance		7,146			7,558			—
Dividends paid		(125,747	)		(119,835	)		(116,510	)
Net cash provided from (used in) financing activities		400,536			(138,263	)		(172,777	)
Net increase (decrease) in cash and cash equivalents		3,115			(4,029	)		(36,912	)
Cash and cash equivalents at the beginning of the year		12,497			16,526			53,438
Cash and cash equivalents at the end of the year	$	15,612		$	12,497		$	16,526
Supplemental disclosures of cash flow information:
Cash paid (received) during the year for:
Interest, net of amounts capitalized	$	166,853		$	144,762		$	154,956
Income taxes (refund)	$	(4,317	)	$	34,627		$	(4,526	)
Non-cash investing activity:
Non-cash plant additions	$	29,927		$	—		$	—
Non-cash financing activity:
Non-cash common share issuance	$	—		$	4,063		$	—

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

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Notes to Consolidated Financial Statements

Note A. Business Organization and Summary of Significant Accounting Policies

1. About NSTAR

NSTAR (or the Company) is a holding company engaged through its subsidiaries in the energy delivery business serving approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric distribution customers in 81 communities and approximately 300,000 natural gas distribution customers in 51 communities. NSTAR’s retail utility subsidiaries are Boston Edison Company (Boston Edison), Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas). Its wholesale electric subsidiary is Canal Electric Company (Canal). NSTAR’s three retail electric companies collectively operate as “NSTAR Electric.” Reference in this report to “NSTAR” shall mean the registrant NSTAR or NSTAR and its subsidiaries as the context requires. Reference in this report to “NSTAR Electric” shall mean Boston Edison, ComElectric and Cambridge Electric together. NSTAR’s non-utility, unregulated operations include district energy operations through its Advanced Energy Systems, Inc. subsidiary (AES), telecommunications operations (NSTAR Communications, Inc. (NSTAR Com)) and a liquefied natural gas service company (Hopkinton LNG Corp.). Utility operations accounted for approximately 96% of consolidated operating revenues in 2005, 2004 and 2003.

2. Basis of Consolidation and Accounting

The accompanying Consolidated Financial Statements reflect the results of operations, comprehensive income, retained earnings, financial position and cash flows of NSTAR and its subsidiaries. All significant intercompany transactions have been eliminated in consolidation. Effective September 30, 2005, NSTAR changed its classification of goodwill to a regulatory asset on the accompanying Consolidated Balance Sheets. For more information refer toNote D. Certain other immaterial reclassifications have been made to prior year amounts to conform to the current year’s presentation.

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

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

3. Revenues

Utility revenues are based on authorized rates approved by the MDTE and FERC. Estimates of distribution and transmission revenues for electricity and natural gas delivered to customers but not yet billed are accrued at the end of each accounting period.

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

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4. Utility Plant

Utility plant is stated at original cost. The cost of replacements of property units is capitalized. Maintenance and repairs and replacements of certain 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	$	724,393	$	695,031
Distribution		3,136,554		2,966,304
General		199,001		211,643
Electric utility plant		4,059,948		3,872,978
Gas -
Transmission and distribution		537,940		507,630
General		73,171		74,166
Gas Utility Plant		611,111		581,796
Total utility plant in service	$	4,671,059	$	4,454,774

5. Non-Utility Plant

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

(in thousands)	2005			2004
Land	$	15,710		$	15,700
Energy production equipment		132,564			136,929
Telecommunications equipment		40,120			39,287
Buildings and improvements		1,364			2,992
		189,758			194,908
Less: accumulated depreciation		(51,536	)		(51,218	)
		138,222			143,690
Construction work in progress		—			458
	$	138,222		$	144,148

6. Depreciation

Depreciation of utility plant is computed on a straight-line basis using composite rates based on the estimated useful lives of the various classes of property. The composite rates are subject to the approval of the MDTE and FERC. The overall composite depreciation rates for utility property were 3.03%, 3.02% and 3.04% 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 $141.4 million, $134 million and $126.8 million, respectively.

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

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

Depreciation expense on non-utility property and equipment was $8.9 million, $9.2 million and $8.3 million for 2005, 2004 and 2003, respectively.

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

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

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

AFUDC represents the estimated costs to finance utility plant construction. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction of current interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the form of increased revenues collected as a result of higher depreciation expense. Average AFUDC rates in 2005, 2004 and 2003 were 3.75%, 1.72% and 1.60%, 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.

NSTAR capitalizes interest costs on long-term construction projects related to its unregulated businesses. Interest costs of $3.7 million during 2003 were capitalized for the construction of new combustion turbines at AES’ MATEP facility. No interest costs were capitalized during 2005 and 2004.

9. Cash, Cash Equivalents and Restricted Cash

Cash, cash equivalents and restricted cash at December 31, 2005 are comprised of liquid securities with maturities of 90 days or less when purchased. Restricted cash primarily represents the funds held by a trustee in connection with Advanced Energy System’s 6.924% Note Agreement, and funds held in reserve for a trust on behalf of Boston Edison and ComElectric to pay the principal and interest on the transition property securitization.

NSTAR’s banking arrangements provide for daily cash transfers to its disbursement accounts as vendor checks are presented for payment. The balances of the disbursement accounts amount to (in thousands) $22,062 and $26,165 at December 31, 2005 and 2004, respectively, and are included in accounts payable on the accompanying Consolidated Balance Sheets. Changes in the balances of the disbursement accounts are reflected in financing activities in the accompanying Statements of Cash Flows.

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10. Equity Method of Accounting

NSTAR uses the equity method of accounting for investments in corporate joint ventures in which it does not have a controlling interest. Under this method, it records as income or loss the proportionate share of the net earnings or losses of the joint ventures with a corresponding increase or decrease in the carrying value of the investment. The investment is reduced as cash dividends are received. NSTAR participates in several corporate joint ventures in which it has investments, principally its 14.5% equity investment in two companies that own and operate transmission facilities to import electricity from the Hydro-Quebec System in Canada, and its equity investments ranging from 4% to 14% in three regional nuclear facilities, two of which are currently being decommissioned. The third plant site has been decommissioned in accordance with the federal Nuclear Regulatory Commission procedures.

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. CTA was being amortized over 10 years at an annual rate of $11.1 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 rate freeze period on August 25, 2003, the amortization expense was increased to reflect the actual CTA final expenditures incurred. As a result, the total CTA amortization expense for 2005 and 2004 was approximately $16.4 million and reflect the final actual CTA of approximately $143 million.

12. Stock Option Plan

NSTAR’s 1997 Share Incentive Plan is a stock-based employee compensation plan and is described more fully in the accompanyingNote J to Consolidated Financial Statements. NSTAR applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25) and related Interpretations in accounting for this plan. Currently, no stock-based employee compensation expense for option grants is reflected in net income, as all options granted under this plan had an exercise price equal to the market value of the underlying common shares on the date of grant. The following table illustrates the effect on net income and earnings per common share if NSTAR had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” to stock-based employee compensation. Refer to Item 14, “New Accounting Standards,” within this Note for the impact of changes in accounting for Share-Based Payment effective January 1, 2006.

(in thousands, except earnings per common share amounts)	Years ended December 31,
	2005			2004			2003
Net income	$	196,135		$	188,481		$	181,574
Add: Share grant incentive compensation expense included in reported net income, net of related tax effects		3,347			2,608			2,147
Deduct: Total share grant and stock option compensation expense determined under fair value method for all awards, net of related tax effects		(4,110	)		(3,385	)		(2,870	)
Pro forma net income	$	195,372		$	187,704		$	180,851
Earnings per common share:
Basic - as reported	$	1.84		$	1.77		$	1.71
Basic - pro forma	$	1.83		$	1.77		$	1.71
Diluted - as reported	$	1.83		$	1.76		$	1.70
Diluted - pro forma	$	1.82		$	1.75		$	1.70

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13. Other Income (Deductions), net

Major components of other income, net were as follows:

	Years ended December 31,
(in thousands)	2005			2004			2003
Equity earnings, dividends and other investment income	$	1,480		$	1,607		$	2,205
Interest and rental income		6,509			4,859			3,244
Sale of unregulated property assets		2,564			1,700			1,386
Tax adjustments		4,735			—			8,485
Miscellaneous other income, (includes applicable income tax expense)		(3,168	)		(861	)		(923	)
	$	12,120		$	7,305		$	14,397

Major components of other deductions, net were as follows:

	Years ended December 31,
(in thousands)	2005			2004			2003
Charitable contributions	$	(2,744	)	$	(2,654	)	$	(1,268	)
Miscellaneous other deductions, (includes applicable income tax benefit (expense))		712			1,167			(444	)
	$	(2,032	)	$	(1,487	)	$	(1,712	)

14. New Accounting Standards

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” This Standard addresses the accounting for transactions in which a company receives employee services in exchange for (a) equity instruments of the company or (b) liabilities that are based on the fair value of the company’s equity instruments or that may be settled by the issuance of such equity instruments. This Standard eliminates the ability to account for share-based compensation transactions using Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and requires that such transactions be accounted for using a fair-value-based method. The Standard is effective for periods beginning January 1, 2006. NSTAR is currently assessing its valuation options allowed in this Standard but, preliminarily, expects this Standard to impact annual earnings by approximately $1.5 million pre-tax. In addition, the Company will use the Modified Prospective method and will utilize the Black-Scholes Option - pricing model to determine the fair value of its compensation expense of these option grants.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” This Standard is effective January 1, 2006 and it 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, NSTAR will adopt this Standard.

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

During 2004, NSTAR Electric 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 NSTAR Electric repurchased its energy resource needs from this independent energy supplier for NSTAR Electric’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 NSTAR Electric’s remaining long-term contracts were bought-out of in February 2005. Refer toNote O, “Contracts for the Purchase of Energy” for more detail on the buy-out of purchase power contracts.

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

Note B. Earnings Per Common Share

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

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

(in thousands, except per share amounts)	2005		2004		2003
Net income	$	196,135	$	188,481	$	181,574
Basic EPS	$	1.84	$	1.77	$	1.71
Diluted EPS	$	1.83	$	1.76	$	1.70
Weighted average common shares outstanding for basic EPS		106,756		106,268		106,065
Effect of dilutive shares:
Weighted average dilutive potential common shares		344		1,024		732
Weighted average common shares outstanding for diluted EPS		107,100		107,292		106,797

Note C. 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 No. 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.

NSTAR adopted FIN 47 at December 31, 2005, as required. The recognition of an ARO within its regulated utility businesses has no impact on NSTAR’s earnings. In accordance with SFAS 71, for its rate-regulated utilities, NSTAR established a regulatory asset to recognize future recoveries through depreciation rates for the recorded ARO. NSTAR 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, NSTAR recognized an asset retirement cost of $0.4 million as an increase in utility property, an asset retirement liability of $9.4 million and a regulatory asset of $9 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 $8.8 million and $8.4 million, respectively.

58

For NSTAR’s regulated utility businesses, the ultimate cost to remove utility plant from service (cost of removal) is recognized as a component of depreciation expense in accordance with approved regulatory treatment. As of December 31, 2005 and 2004, the estimated amount of the cost of removal included in regulatory liabilities was approximately $259 million based on the estimated cost of removal component in current depreciation rates.

Note D. Changes in Classification of Goodwill

Effective September 30, 2005, NSTAR changed its classification of the amount included as Goodwill in the December 31, 2004 Consolidated Balance Sheet of $415.5 million to a Deferred debit - Regulatory asset - goodwill. As a result of this change in classification to a regulatory asset and in accordance with the requirements of SFAS 109, “Accounting for Income Taxes,” the Company recognized $268.2 million of accumulated deferred income taxes along with an offsetting regulatory asset as of September 30, 2005. The new classification of goodwill was adopted to better align with the Company’s recovery of goodwill amortization from its customers. For comparative purposes, NSTAR has adopted the new classification retrospectively to the financial statements of prior periods. The regulatory asset, representing the accumulated deferred income taxes, will be amortized over the remaining life of the regulatory asset - goodwill in accordance with the Company’s merger rate order allowing recovery of goodwill amortization and amounts to approximately $7.9 million annually. This additional amortization expense is entirely offset by a corresponding deferred income tax - benefit.

The Company’s goodwill arose from the merger that created NSTAR in 1999. As a result of a rate order from the MDTE approving the merger, the Company is recovering goodwill from its customers and, therefore, NSTAR has determined that this rate structure allows for amortization of goodwill over the collection period.

This classification change had no effect on prior year earnings and, therefore, there has been no change to previously reported retained earnings.

A summary of the impact of the classification change for the years ended December 31, 2004 and 2003 is as follows: (in thousands)

	Year Ended December 31, 2004
	Previously Reported		As Adjusted		Effect of Change
Consolidated Income Statement
Depreciation and amortization	$	246,944	$	254,852	$	7,908
Income taxes		116,238		108,330		(7,908	)
	Previously Reported		As Adjusted		Effect of Change
Consolidated Statement of Cash Flows
Depreciation and amortization	$	246,363	$	254,271	$	7,908
Deferred Income taxes		79,570		71,662		(7,908	)
	December 31, 2004
	Previously Reported		As Adjusted		Effect of Change
Consolidated Balance Sheet
Goodwill	$	426,870	$	—	$	(426,870	)
Current regulatory asset		280,078		300,238		20,160
Deferred debit regulatory asset - goodwill		—		678,698		678,698
Accumulated deferred income taxes		840,461		1,114,588		274,127
	Year Ended December 31, 2003
	Previously Reported		As Adjusted		Effect of Change
Consolidated Income Statement
Depreciation and amortization	$	235,516	$	243,424	$	7,908
Income taxes		121,409		113,501		(7,908	)

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	Year Ended December 31, 2003
	Previously Reported		As Adjusted		Effect of Change
Consolidated Statement of Cash Flows
Depreciation and amortization	$	236,336	$	244,244	$	7,908
Deferred income taxes		128,379		120,471		(7,908	)

Note E. Regulatory Assets

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

Regulatory assets consisted of the following:

	December 31,
(in thousands)	2005		2004
Energy contracts (including Yankee units)	$	866,867	$	1,440,963
Goodwill		678,698		698,858
Regulatory assets - other:
Generation-related costs		909,651		520,481
Merger costs to achieve		60,247		76,680
Income taxes, net		50,058		50,292
Purchased energy costs		44,665		—
Redemption premiums		14,896		16,785
Retiree benefit costs		23,090		34,558
Other		64,538		17,007
Total current and long-term regulatory assets	$	2,712,710	$	2,855,624

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

Energy contracts

The unamortized balance of the estimated costs to decommission the Connecticut Yankee (CY) and Yankee Atomic (YA) nuclear power plants was $102.7 million at December 31, 2005. The Maine Yankee (MY) nuclear unit was notified on October 3, 2005 by the U.S. Nuclear Regulatory Commission (NRC) that its former plant site has been decommissioned in accordance with NRC procedures. NSTAR’s liability for CY decommissioning and its recovery ends in 2010, for YA in 2010 and for MY in 2010. However, should the actual costs exceed current estimates and anticipated decommissioning dates, NSTAR could have an obligation beyond these periods that would be fully recoverable. These costs are recovered through NSTAR Electric’s transition charge. NSTAR does not earn a return on decommissioning costs, but a return is included in rates charged to NSTAR by the plant operators. Refer toNote P, “Commitments and Contingencies,” for more discussion.

In addition, at December 31, 2004, $472.3 million represents the recognition of four purchase power contracts as derivatives and their above-market value and future recovery through NSTAR Electric’s transition charges. Refer toNote F, “Derivative Instruments - Energy Contracts” for further details. On March 1, 2005, NSTAR closed on a securitization financing for $674.5 million to, in part, finance the buy-out of these four contracts. The remaining balance at December 31, 2005 of $764.2 million represents their future recovery through NSTAR

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

For the power contracts that were terminated, NSTAR does not earn a return on this regulatory asset. NSTAR 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, NSTAR 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 NSTAR to create the regulatory asset. The contracts’ termination payments will occur over time and will be collected from customers through NSTAR’s transition charge over the same time period. The cost recovery of these terminated contracts is through September 2016.

Goodwill

The Company’s goodwill originated from the merger that created NSTAR in 1999. As a result of a rate order from the MDTE approving the merger, the Company is recovering goodwill from its customers and, therefore, NSTAR has determined that this rate structure allows for amortization of goodwill over the collection period.

In the third quarter of 2005, NSTAR changed its classification of the amount included as Goodwill in the December 31, 2004 Consolidated Balance Sheet of $415.5 million to a Deferred debit - Regulatory asset - goodwill. As a result of this change in classification to a regulatory asset and in accordance with the requirements of SFAS 109, “Accounting for Income Taxes,” the Company recognized $268.2 million of accumulated deferred income taxes along with an offsetting regulatory asset as of September 30, 2005. Goodwill along with deferred income taxes is being amortized over 40 years, through 2039, without a carrying charge. Refer toNote D,“Change in Classification of Goodwill” for further details.

Generation-related costs

Costs related to purchase power contract buyouts and the divestiture of NSTAR’s generation business are recovered with a return through the transition charge. This recovery occurs through 2019 for Boston Edison and through 2023 for ComElectric. This schedule is subject to adjustment by the MDTE.

As of December 31, 2005 and 2004, $892.4 million and $357.2 million 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 and to ComElectric’s subsidiary, CEC Funding, LLC. The certificates are non-recourse to both Boston Edison and ComElectric.

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 all NSTAR Electric and NSTAR Gas 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 toNote A to these Consolidated Financial Statements for more information on merger costs to achieve.

Income taxes, net

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

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Purchased energy costs

The purchased energy costs at December 31, 2005 relate to deferred electric basic service and gas costs. Prior to March 1, 2005, customers had the option of continuing to buy electricity from the retail electric distribution businesses at standard offer prices. Since 1998, NSTAR 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. Deferred gas costs are deferred and are recovered from customers in the future.

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.

Retiree benefit costs

The retiree benefit regulatory asset at December 31, 2005 of $23.1 million is comprised of $18.4 million in carrying charges that will be recovered from customers commencing in 2006 related to its qualified pension and other postretirement benefit obligations. There are $4.7 million of pension and PBOP expenses deferred under the MDTE order through 2005. Deferred pension and PBOP costs are amortized and collected from customers over three years. NSTAR 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.

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.

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

Note F. Derivative Instruments

Energy 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 their customer base, an option contract for the purchase of electricity typically qualifies for the normal purchases and sales exception as described in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133) and Derivative Implementation Group (DIG) interpretations and, therefore, does not require mark-to-market accounting. NSTAR accounts for its energy contracts in accordance with SFAS 133 and SFAS No. 149, “Amendment of Statement No. 133 on Derivative Instruments and Hedging Activities” (SFAS 149).

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NSTAR Electric has long-term purchase power agreements that were 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, NSTAR, as of December 31, 2004, had four remaining contracts that were recorded at fair value on the accompanying Consolidated Balance Sheets. On March 1, 2005, NSTAR closed on a securitization financing for $674.5 million to, in part, finance the buy-out of these remaining four contracts that were classified as derivative instruments at December 31, 2004. These four contracts had an aggregate fair value of approximately $472 million at December 31, 2004 and were therefore removed as a derivative instrument from Deferred credits - Energy 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 electric distribution companies’ transition charge. At December 31, 2005, NSTAR does not have any contracts that continue to be classified as derivative instruments. Refer to the accompanying Consolidated Financial Statements,Note O, for more detail on the buy-out of certain purchase power contracts.

Hedging Agreements

On February 28, 2005, the MDTE approved a petition by NSTAR Gas to change a portion of its gas procurement practices. As approved, NSTAR Gas began purchasing financial contracts based upon NYMEX natural gas futures in order to reduce cash flow variability associated with the purchase price for approximately one-third of its natural gas purchases. Ultimately, this will minimize fluctuations in prices to NSTAR firm gas sales customers. NSTAR Gas will not take physical delivery of gas when the financial contracts are executed. These contracts qualify as derivative financial instruments and, specifically, cash flow hedges under SFAS 133, as amended by SFAS 149. Accordingly, the fair value of these instruments will be recognized on the accompanying Consolidated Balance Sheet as a deferred asset or liability representing amounts due from or payable to the counter parties of NSTAR Gas. All costs incurred are included in the firm sales Cost of Gas Adjustment Clause (CGAC). Therefore, NSTAR Gas will record an offsetting regulatory asset or liability. Management has begun to implement this practice with two major financial institutions. Currently, these derivative contracts extend through April 2006. At December 31, 2005, NSTAR has recorded a liability and a corresponding regulatory asset of $0.3 million reflecting the fair value of these contracts.

Note G. 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.

NSTAR has three wholly owned special purpose subsidiaries, BEC Funding LLC., established in 1999, BEC Funding II, LLC and CEC Funding, LLC both established in 2004, to undertake the sale of $725 million, $265.5 million and $409 million, respectively, in notes to a special purpose trust created by two Massachusetts state agencies. NSTAR consolidates these entities. As part of NSTAR’s assessment of FIN 46R and, for compliance at December 31, 2003 or 2004, NSTAR reviewed the substance of these entities to determine if it is still proper to consolidate these entities. Based on its review, NSTAR has concluded that BEC Funding LLC, BEC Funding II, LLC and CEC Funding, LLC are VIEs and should continue to be consolidated by NSTAR.

For the March 31, 2004 effective date of FIN 46R, NSTAR evaluated other entities with which it conducts significant transactions, including companies that supply power to NSTAR through its purchase power agreements. NSTAR determined that it is possible that five of these companies may be considered VIEs. In order

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to determine if these counterparties are VIEs and if NSTAR is the primary beneficiary of these counterparties, NSTAR concluded that it needed more information from the entities. NSTAR attempted to obtain the information required and requested, in writing, these entities provide the Company with the necessary information. However, each of the entities has indicated that they will not provide the requested information as they are not contractually obligated to provide such confidential information. Since NSTAR was unable to obtain the necessary information and, as allowed under a scope exception in FIN 46R, the accompanying Consolidated Financial Statements do not reflect the consolidation of any entities with which NSTAR has a purchase power agreement.

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

Note H. Income Taxes

Income taxes are accounted for in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS 109). SFAS 109 requires the recognition of deferred tax assets and liabilities for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 71 and SFAS 109, net regulatory assets of $50.1 million and $50.3 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	$	560,445	$	555,095
Goodwill		266,219		274,127
Power contracts		188,194		—
Transition costs		123,149		151,015
Other		259,781		263,783
		1,397,788		1,244,020
Deferred tax assets:
Plant-related		46,224		50,864
Investment tax credits		15,428		16,101
Other		78,925		79,588
		140,577		146,553
Net accumulated deferred income taxes		1,257,211		1,097,467
Accumulated unamortized investment tax credits		23,477		25,193
	$	1,280,688	$	1,122,660

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

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Components of income tax expense were as follows:

(in thousands)	2005			2004			2003
Current (benefit) income tax expense	$	(52,959	)	$	36,668		$	39,188
Deferred income tax expense		165,364			73,378			76,036
Investment tax credit amortization		(1,715	)		(1,716	)		(1,723	)
Income taxes charged to operations		110,690			108,330			113,501
Tax expense (benefit) on other income net:
Current income tax expense (benefit)		3,703			2,989			(54,668	)
Deferred income tax (benefit) expense		(4,735	)		—			46,157
Income tax (benefit) expense on other income, net		(1,032	)		2,989			(8,511	)
Total income tax expense	$	109,658		$	111,319		$	104,990

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

	2005		2004		2003
Statutory tax rate	35.0	%	35.0	%	35.0	%
State income tax, net of federal income tax benefit	4.6		4.0		5.3
Investment tax credits	(0.6	)	(0.6	)	(0.6	)
Other	(1.6	)	(1.3	)	(0.3	)
Effective tax rate before tax adjustments	37.4		37.1		39.4
Tax adjustments	(1.5	)	—		(2.8	)
Effective tax rate	35.9	%	37.1	%	36.6	%

RCN Corporation (RCN) Share Abandonment Tax Treatment

On December 24, 2003, NSTAR exited its investment in RCN and formally abandoned its 11.6 million shares of RCN common stock. As a result, NSTAR recorded a pre-tax charge of approximately $6.8 million, or $0.08 per share reflecting the writedown of its investment to zero as of December 31, 2003. NSTAR determined that the abandonment at that time was the most tax efficient, cost effective and expedient means to exit its RCN investment. NSTAR also determined that the benefit of a tax realization event at that time and in that manner outweighed any benefit that it would likely realize from any other alternative, including the future sale of such shares in an orderly fashion consistent with all laws, rules and regulations.

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

It is NSTAR’s tax accounting policy to not recognize tax benefits associated with an uncertain tax position until it is probable that such tax benefit will ultimately be realized. Since NSTAR is under continuous audit by the Internal Revenue Service (IRS), NSTAR consulted with its independent tax advisors and determined that it could not conclude that it is probable that the tax deduction related to the abandonment of its RCN investment will be sustained. Accordingly, NSTAR accrued a tax reserve so as to not record the tax benefit of the uncertain tax position.

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The Company believes it is more likely than not that it is entitled to this ordinary loss deduction, but expects the IRS will review this transaction and it is possible that the IRS will disagree with the Company’s position. In accordance with the Company’s tax policy as it relates to uncertain tax positions, NSTAR established a loss contingency of approximately $44.4 million at December 31, 2003. This amount represents the tax impact to the Company should the ordinary loss ultimately be recharacterized to a capital loss and would be reclassified as a tax valuation allowance. During 2005, the Company recognized approximately $4.7 million in tax benefits relating to capital tax gain transactions. As a result, the Company reduced its tax loss contingency by a corresponding amount. Therefore, as of December 31, 2005, the tax loss contingency is approximately $39.7 million. This contingent liability is recorded as part of Deferred credits - Other on the accompanying Consolidated Balance Sheets.

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

Note I. Pension and Other Postretirement Benefits

1. Pension

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

The Plan uses December 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	$	1,059,398		$	961,029
Service cost		20,689			19,038
Interest cost		57,634			60,165
Plan participants’ contributions		42			61
Actuarial (gain) loss		(24,664	)		90,693
Settlement payments		(23,726	)		(18,588	)
Benefits paid		(53,815	)		(53,000	)
Benefit obligation, end of the year	$	1,035,558		$	1,059,398
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		77,546			42,724
Plan participants’ contributions		42			61
Settlement payments		(23,726	)		(18,588	)
Benefits paid		(53,815	)		(53,000	)
Fair value of Plan assets, end of the year	$	964,613		$	894,754

The market-related value of NSTAR’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.

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The Plan’s funded status was as follows:

	December 31,
(in thousands)	2005			2004
Funded status	$	(70,945	)	$	(164,644	)
Unrecognized actuarial net loss		397,149			443,437
Unrecognized prior service cost		(3,228	)		(3,096	)
Net amount recognized	$	322,976		$	275,697

Amounts recognized in the accompanying Consolidated Balance Sheets consisted of:

	December 31,
(in thousands)	2005			2004
Accrued retirement liability	$	(37,351	)	$	(31,297	)
Intangible asset		2,570			3,513
Accumulated other comprehensive income		10,868			5,735
Prepaid pension		346,889			297,746
Net amount recognized	$	322,976		$	275,697

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.

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the nonqualified retirement plan were $40,596,000, $37,351,000 and $0, respectively, as of December 31, 2005 and were $36,415,000, $31,297,000 and $0, respectively, as of December 31, 2004.

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 Plans’ discount rates are 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 Company’s plans and through periodic bond portfolio matching. The Plans’ long-term rates of return are based on past performance and economic forecasts for the types of investments held in the Plan as well as the target allocation of the investments over a 20-year time period. This rate is presented net of both administrative expenses and investment expenses, which have averaged approximately 0.6% for 2005 and 2004.

Components of net periodic benefit cost were as follows:

	Years ended December 31,
(in thousands)	2005			2004			2003
Service cost	$	20,689		$	19,038		$	17,976
Interest cost		57,634			60,165			58,826
Expected return on Plan assets		(74,390	)		(70,794	)		(58,917	)
Amortization of prior service cost		133			133			133
Amortization of transition obligation		—			379			601
Recognized actuarial loss		26,202			26,931			33,514
Net periodic benefit cost	$	30,268		$	35,852		$	52,133

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

	Plan Assets				Target Percentages		Permissible Ranges
	2005		2004					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 its plan assets. Assets are diversified by both asset class (i.e., equities, bonds) and within these classes (i.e., economic sector, industry), such that, for each asset manager:

• No more than 6% of an asset manager’s equity portfolio market value may be invested in one company

• Each portfolio should be invested in at least 20 different companies in different industries, and

• No more than 50% of each portfolio’s market value may be invested in one industry sector.

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

As a result of the significant contributions made in 2005, NSTAR 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	$	61,271
2007		64,613
2008		65,611
2009		73,870
2010		73,597
2011 - 2015		414,821
Total	$	753,783

2. Other Postretirement Benefits

NSTAR also provides health care and other benefits to retired employees who meet certain age and years of service eligibility requirements. These benefits include health and life insurance coverage and until April 1, 2003 included reimbursement of certain Medicare premiums for certain retirees. Under certain circumstances, eligible retirees are required to contribute for postretirement benefits.

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was reflected as of January 1, 2004 by NSTAR assuming continuation of prescription drug benefits to retirees that are at least actuarially equivalent to the benefits provided under Medicare Part D. The Act provides for drug benefits for

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participants over the age of 65 under a new Medicare Part D program. For employers like NSTAR, who continue to provide prescription drug programs for eligible former employees over the age of 65, there are subsidies available that are contained in the Act in the form of direct tax-exempt cash payments.

In May 2004, the FASB provided guidance on the accounting for the effects of the Act. The guidance requires that, when an employer initially accounts for the effects of the Act, the impact on the accumulated postretirement benefits obligation (APBO) should be accounted for as an actuarial gain (assuming, no plan amendments are made). In accordance with this provision, NSTAR’s APBO was reduced by approximately $51 million in 2004. In addition, since the subsidy affects the employer’s share of its plan’s costs, the subsidy is included in measuring the costs of benefits attributable to current service. Therefore, the subsidy reduces service cost when it is recognized as a component of net periodic postretirement benefits cost. NSTAR’s adoption of the accounting guidance resulted in a reduction to the net periodic postretirement benefit cost of approximately $9.7 million and $7 million in 2005 and 2004, respectively, and is reflected as a component of net periodic postretirement benefits costs. However, as a result of the Company’s pension and other postretirement benefits rate reconciliation adjustment mechanism, these reductions do not have a material impact on reported earnings.

NSTAR’s other postretirement plans use December 31^st for the measurement date to determine its benefit obligation and fair value of plan assets for the purposes of determining the plans’ 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	$	600,430		$	595,483
Service cost		5,733			5,828
Interest cost		33,342			33,395
Plan participants’ contributions		2,204			1,835
Plan amendments		(17,789	)		—
Actuarial loss (gain)		3,002			(6,993	)
Benefits paid		(31,250	)		(29,118	)
Benefit obligation, end of the year	$	595,672		$	600,430
Change in plan assets:
Fair value of plan assets, beginning of the year	$	305,309		$	280,032
Actual gain on plan assets		19,028			32,539
Employer contribution		40,047			20,021
Plan participants’ contributions		2,204			1,835
Benefits paid		(31,250	)		(29,118	)
Fair value of plan assets, end of the year	$	335,338		$	305,309

The plans’ funded status was as follows:

	December 31,
(in thousands)	2005			2004
Funded status	$	(260,334	)	$	(295,121	)
Unrecognized actuarial net loss		205,569			207,786
Unrecognized transition obligation		5,810			14,575
Unrecognized prior service cost		(916	)		9,570
Net amount recognized	$	(49,871	)	$	(63,190	)

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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	9.0	%	8.0	%	8.0	%

For measurement purposes, a 9.0% weighted annual rate increase in per capita cost of covered medical claims was assumed for 2006. This rate is assumed to decrease gradually to 5% in 2013 and remain at that level thereafter. Dental claims are assumed to increase at a weighted annual rate of 4%.

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

	One-Percentage-Point
(in thousands)	Increase		Decrease
Effect on total service and interest cost components for 2005	$	6,378	$	(5,041	)
Effect on December 31, 2005 postretirement benefit obligation	$	92,745	$	(74,689	)

Components of net periodic benefit cost were as follows:

	Years ended December 31,
(in thousands)	2005			2004			2003
Service cost	$	5,733		$	5,828		$	7,076
Interest cost		33,342			33,395			35,383
Expected return on plan assets		(25,027	)		(23,759	)		(19,088	)
Amortization of prior service cost		222			1,285			1,285
Amortization of transition obligation		1,241			1,821			1,821
Recognized actuarial loss		11,216			9,598			13,303
Net periodic benefit cost	$	26,727		$	28,168		$	39,780

As a result of the significant contributions made in 2005, NSTAR does not anticipate making any contribution to its other postretirement benefit plans in 2006.

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

(in thousands)
2006	$	29,767
2007		31,309
2008		32,704
2009		34,311
2010		35,744
2011 - 2015		199,082
Total	$	362,917

The estimated expected cash flows from the Medicare subsidy for the years after 2005 are as follows:

(in thousands)
2006	$	2,236
2007		2,512
2008		2,793
2009		3,050
2010		3,289
2011 - 2015		19,520
Total	$	33,400

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

Asset Category	Plan Assets				Target Percentages		Permissible           Ranges	Benchmark
	2005		2004
Equity securities	47	%	50	%	50	%	45% - 55%	Russell 3000 Index
Debt securities	35	%	31	%	30	%	25% - 35%	Lehman Aggregate
Real Estate	9	%	10	%	10	%	5% - 15%	Wilshire NAREIT Index
Other	9	%	9	%	10	%	5% - 15%
Total	100	%	100	%	100	%

Other asset category consists of hedge funds and common/collective trusts.

The assets of NSTAR’s PBOP Plan are held in voluntary employees’ beneficiary association trusts and in the Pension Plan 401(h) account which is a subset of the Pension Plan assets and are not reflected as a component of the PBOP Plan assets.

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

3. Savings Plan

NSTAR also provides a defined contribution 401(k) plan for substantially all employees. Matching contributions (which are equal to 50% of the employees’ deferral up to 8% of eligible base and cash bonus compensation) included in the accompanying Consolidated Statements of Income amounted to $9 million in 2005, $8 million in 2004 and $9 million in 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 J. Stock-Based Compensation

NSTAR’s Share Incentive Plan (the Plan) permits a variety of stock and stock-based awards, including stock options and deferred (non-vested) stock to be granted to key employees. The Plan limits the terms of awards to ten years. Subject to adjustment for stock-splits and similar events, the aggregate number of common shares that may be awarded under the Plan is four million. As adjusted for the effect of the common stock split that occurred in 2005, there were 2,116,472 unissued shares available under this Plan as of December 31, 2005. The weighted average grant date fair value of the deferred stock issued during 2005, 2004 and 2003 was $29.60, $24.21 and $21.60, respectively. During 2005, 371,419 deferred shares and 586,000 ten-year non-qualified stock options were granted. During 2004, 216,700 deferred shares and 632,000 ten-year non-qualified stock options were granted under the Plan. During 2003, 219,800 deferred shares and 648,000 ten-year non-qualified stock options were granted under the Plan. The options were granted at the full market price of the common shares on the date of the grant. All the awards vest ratably over a three-year period. Refer to the Consolidated Financial Statements,Note A, for more details.

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Stock option activity of the Plan was as follows:

	2005 Activity		Weighted Average Exercise Price		2004 Activity		Weighted Average Exercise Price		2003 Activity		Weighted Average Exercise Price
Options outstanding at January 1	2,912,338		$	21.73	2,425,538		$	21.01	2,093,738		$	20.07
Options granted	586,000		$	29.60	632,000		$	24.21	648,000		$	21.60
Options exercised	(909,937	)	$	20.18	(145,200	)	$	20.52	(281,334	)	$	15.27
Options forfeited	—			—	—		$	—	(34,866	)	$	21.78
Options outstanding at December 31	2,588,401		$	24.05	2,912,338		$	21.73	2,425,538		$	21.01

Summarized information regarding stock options outstanding at December 31, 2005:

		Options Outstanding			Options Exercisable
Range of Exercise Prices	Number Outstanding	Weighted Average Remaining Contractual Life (Years)	Weighted Average Exercise Price		Number Outstanding	Weighted Average Exercise Price
$19.88	39,400	2.26	$	19.88	39,400	$	19.88
$22.19	229,000	4.40	$	22.19	229,000	$	22.19
$19.85	170,000	5.40	$	19.85	170,000	$	19.85
$22.06 - $22.67	415,999	6.30	$	22.61	415,999	$	22.61
$21.60	550,666	7.33	$	21.60	368,946	$	21.60
$24.21	597,336	8.33	$	24.21	197,120	$	24.21
$29.60	586,000	9.44	$	29.60	—		—

There were 1,420,465, 1,689,978 and 1,344,946 stock options exercisable on December 31, 2005, 2004 and 2003, respectively. The weighted average exercise price of these options exercisable are $22.09, $20.75 and $20.42, respectively.

The stock options granted during 2005, 2004 and 2003 have a weighted average grant date fair value of $2.74, $3.74 and $3.85, respectively. The fair value was estimated using the Black-Scholes option-pricing model with the following weighted average assumptions:

	2005		2004		2003
Expected life (years)	6.0		4.0		4.0
Risk-free interest rate	3.76	%	3.39	%	2.54	%
Volatility	15	%	15	%	18	%
Dividends	4.69	%	4.90	%	4.97	%

Compensation cost recognized in the accompanying Consolidated Statements of Income for deferred share awards in 2005, 2004 and 2003 was $5,507,458, $4,282,561 and $3,530,719, respectively.

Note K. Capital Stock

At NSTAR’s Annual Meeting of Shareholders held on April 28, 2005, shareholders approved an increase in the number of the Company’s authorized shares from 100 million to 200 million. Subsequently, the Board of Trustees approved a two-for-one stock split of NSTAR’s common shares, in the form of a 100% common share dividend, to shareholders of record on May 16, 2005. The new shares were issued on June 3, 2005. The Company’s intent in effecting a stock split in the form of a stock dividend was to increase the number of outstanding common shares and to reduce the per share stock price thereby making it more accessible to investors. Common equity, common shares, and stock option activity for all periods presented have been restated

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to give retroactive recognition to the stock split. In addition, all references in the financial statements and notes to the financial statements, to weighted average number of basic and diluted shares, and per share amounts of the Company’s common shares have been restated to give retroactive recognition to the stock split.

Dividends declared per common share were $0.87, $1.1225 and $1.0875 in 2005, 2004 and 2003, respectively. As a result of a change in NSTAR’s Board of Trustee meetings schedule in 2005, the fourth quarter dividend, typically declared in December, of $0.3025 per share was approved on January 26, 2006. The dividend payment schedule remains unchanged.

1. Common Shares

Common share issuances and repurchases in 2004 through 2005 were as follows:

(in thousands)	Number of Shares	Total Par Value		Premium on Common Shares
Balance at December 31, 2003	106,066	$	106,066	$	813,188
Share Incentive Plan issuance	172		172		3,891
Share Incentive Plan	—		—		(4,871	)
Dividend Reinvestment and Direct Common Shares Purchase Plan	312		312		7,246
Balance at December 31, 2004	106,550		106,550		819,454
Share Incentive Plan	—		—		(13,243	)
Dividend Reinvestment and Direct Common Shares Purchase Plan	258		258		6,888
Balance at December 31, 2005	106,808	$	106,808	$	813,099

In connection with the NSTAR Dividend Reinvestment and Direct Common Shares Purchase Plan, NSTAR issued approximately 258,000 shares under this registration and received approximately $7.1 million in 2005.

2. Cumulative Preferred Stock of Subsidiary

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)
Series	Current Shares     Outstanding	Redemption Price/Share		December 31, 2005		December 31, 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 Company has two outstanding series of non-mandatory redeemable preferred stock. Both series are part of a class of Boston Edison Company’s Cumulative Preferred Stock. Upon any liquidation of Boston Edison Company, 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.

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Note L. Indebtedness

1. Long-Term Debt

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

	December 31,
(in thousands)	2005			2004
Mortgage Bonds/Notes, collateralized by property of operating subsidiaries:
6.54%, due September 2007	$	2,857		$	4,286
7.04%, due September 2017		25,000			25,000
9.95%, due December 2020		25,000			25,000
7.11%, due December 2033		35,000			35,000
6.924%, due June 2021		103,947			107,548
Notes:
Variable Rate (3.0275% in 2004) due May 2006		—			150,000
7.62%, due November 2006		20,000			20,000
8.70%, due March 2007		5,000			5,000
9.55%, due December 2007		2,857			4,286
7.70%, due March 2008		10,000			10,000
8.0%, due February 2010		500,000			500,000
9.37%, due January 2012		7,368			8,421
7.98%, due March 2013		25,000			25,000
9.53%, due December 2014		10,000			10,000
9.60%, due December 2019		10,000			10,000
8.47%, due March 2023		15,000			15,000
Debentures:
Floating Rate (2.57% in 2004) due October 2005		—			100,000
7.80%, due May 2010		125,000			125,000
4.875%, due October 2012		400,000			400,000
4.875%, due April 2014		300,000			300,000
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
3.40%, due September 2006		36,836			—
6.91%, due September 2007		108,923			170,876
3.78%, due September 2008		154,018			—
7.03%, due March 2010		171,624			171,624
4.13%, due September 2011		266,477			—
4.40%, due September 2013		144,771			—
		2,534,580			2,260,928
Unamortized debt discount		(9,063	)		(10,281	)
Amounts due within one year		(123,140	)		(149,245	)
Total long-term debt	$	2,402,377		$	2,101,402

On March 1, 2005, ComElectric redeemed its $150 million variable rate notes due May 2006.

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.

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.

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.

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The aggregate principal amounts of NSTAR long-term debt (including securitization certificates and sinking fund requirements) due in the five years subsequent to 2005 are approximately $123 million in 2006, $166 million in 2007, $170 million in 2008, $160 million in 2009 and $752 million in 2010.

The Transition Property Securitization Certificates held by Boston Edison’s subsidiaries, BEC Funding LLC and BEC Funding II, LLC, are each collaterized with separate securitized regulatory assets with combined balances of $526.1 million and $357.2 million as of December 31, 2005 and 2004, respectively. Boston Edison, as servicing agent for BEC Funding LLC and BEC Funding II, LLC collected $129.2 million in 2005. In addition, the Transition Property Securitization Certificates held by ComElectric’s subsidiary, CEC Funding, LLC, are collaterized with a securitized regulatory asset with a balance of $366.4 million as of December 31, 2005. ComElectric, as servicing agent for CEC Funding, LLC collected $57.7 million in 2005. Funds collected from the companies’ respective customers are transferred to each Funding companies’ Trust on a daily basis. These Certificates are non-recourse to Boston Edison and ComElectric.

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

2. Financial Covenant Requirements and Lines of Credit

NSTAR and Boston Edison have no financial covenant requirements under their respective long-term debt arrangements. ComElectric, Cambridge Electric and NSTAR Gas have financial covenant requirements under their long-term debt arrangements and were in compliance at December 31, 2005 and 2004. NSTAR’s long-term debt other than the Mortgage Bonds, Notes of NSTAR Gas and Medical Area Total Energy Plant, Inc., a wholly owned subsidiary of NSTAR, is unsecured.

NSTAR has executed a five-year, $175 million revolving credit agreement that expires in November 2009. At December 31, 2005 and 2004, there were no amounts outstanding under the revolving credit agreement. This credit facility serves as a backup to NSTAR’s $175 million commercial paper program that, at December 31, 2005 and 2004, had $66 million and $5 million outstanding, respectively. Under the terms of the credit agreement, NSTAR is required to maintain a maximum total consolidated debt to total capitalization ratio of not greater than 65% at all times, excluding Transition Property Securitization Certificates, and excluding Accumulated other comprehensive income (loss) from common equity. Commitment fees must be paid on the total agreement amount. At December 31, 2005 and 2004, NSTAR was in compliance with the aforementioned covenant as the ratios were 56.7% and 58.3% respectively.

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 compliance with its covenants in connection with its short-term credit facilities as the ratios were 45.9% and 53.1%, respectively.

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As of December 31, 2005, ComElectric, Cambridge Electric and NSTAR Gas, collectively, have $245 million available under several lines of credit and had $154.5 million and $109.9 million outstanding under these lines of credit at December 31, 2005 and 2004, respectively. As of September 28, 2004, ComElectric and Cambridge Electric have FERC authorization to issue short-term debt securities from time-to-time on or before November 30, 2006 and June 27, 2006, with maturity dates no later than November 30, 2007 and June 27, 2007, respectively, in amounts such that the aggregate principal does not exceed $125 million and $60 million, respectively, at any one time. NSTAR Gas is not required to seek approval from FERC to issue short-term debt.

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

Interest rates on the outstanding borrowings generally are money market rates and averaged 3.54% and 1.38% in 2005 and 2004, respectively. In aggregate, short-term borrowings totaled $417.5 million and $161.4 million at December 31, 2005 and 2004, respectively.

Note M. Fair Value of Financial Instruments

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

1. Cash and Cash Equivalents

The carrying amounts of $15.6 million and $12.5 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
(in thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term indebtedness (including current maturities)	$	2,525,517	$	2,642,190	$	2,250,647	$	2,483,220

Note N. Segment and Related Information

For the purpose of providing segment information, NSTAR’s principal operating segments, or its traditional core businesses, are the electric and natural gas utilities that provide energy delivery services in 107 cities and towns in Massachusetts. The unregulated operating segment engages in business activities that include district energy operations, telecommunications and liquefied natural gas service.

Amounts shown on the following table for 2005, 2004 and 2003 include the allocation of NSTAR’s (parent company) results of operations and assets, net of inter-company transactions, and primarily consist of interest charges and investment assets, respectively, to these business segments. The allocation of parent company charges is based on an indirect allocation of the parent company’s investment relating to these various business segments.

The unregulated net income for 2005 as compared to 2004 reflects higher revenues for steam, chilled water and electricity sales offset by the partial absence of NSTAR Steam Corporation which ceased operations in September 2005. The unregulated net income for 2004 as compared to 2003 reflects the absence of operations in 2004 of results of operations from the Blackstone Station due to its sale in 2003 and the resulting impact of decreased income on NSTAR Steam Corporation, offset by a higher gross margin at AES primarily due to increased steam sales and higher demand revenues. In addition, on December 24, 2003, NSTAR abandoned the 11.6 million shares of RCN common stock and recorded a pre-tax charge of $6.8 million including expenses. Offsetting the 2003 RCN abandonment loss is the recognition of $6.8 million of tax benefits resulting from unanticipated capital gain transactions.

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

(in thousands)	2005		2004		2003
Operating revenues
Electric utility operations	$	2,543,541	$	2,350,185	$	2,333,235
Gas utility operations		571,199		492,338		465,209
Unregulated operations		128,380		111,809		113,267
Consolidated total	$	3,243,120	$	2,954,332	$	2,911,711
Depreciation and amortization
Electric utility operations	$	299,741	$	218,915	$	209,688
Gas utility operations		22,435		21,310		20,064
Unregulated operations		14,494		14,627		13,672
Consolidated total	$	336,670	$	254,852	$	243,424
Operating income tax expense (benefit)
Electric utility operations	$	92,239	$	90,891	$	96,908
Gas utility operations		13,589		13,979		14,829
Unregulated operations		4,862		3,460		1,764
Consolidated total	$	110,690	$	108,330	$	113,501
Equity income in investments accounted for by the equity method (a)
Electric utility operations	$	1,480	$	1,607	$	2,205
Interest charges
Electric utility operations	$	143,044	$	128,306	$	134,513
Gas utility operations		14,643		15,677		14,203
Unregulated operations		9,876		9,722		8,496
Consolidated total	$	167,563	$	153,705	$	157,212
Segment net income
Electric utility operations	$	157,235	$	156,679	$	150,249
Gas utility operations		25,310		25,801		24,441
Unregulated operations		13,590		6,001		6,884
Consolidated total	$	196,135	$	188,481	$	181,574
Equity Investments
Electric utility operations	$	13,705	$	13,887	$	15,322
Net expenditures for property
Electric utility operations	$	337,519	$	272,794	$	240,699
Gas utility operations		40,361		35,262		30,167
Unregulated operations		5,676		5,331		36,789
Consolidated total	$	383,556	$	313,387	$	307,655
Segment assets
Electric utility operations	$	6,658,805	$	6,494,568	$	5,664,553
Gas utility operations		790,155		695,329		719,706
Unregulated operations		196,604		201,459		229,927
Consolidated total	$	7,645,564	$	7,391,356	$	6,614,186

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

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Note O. Contracts for the Purchase of Energy

1. NSTAR Electric Purchase Power Agreements

As a Massachusetts distribution company, NSTAR Electric 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, NSTAR Electric makes periodic market solicitations consistent with MDTE regulations. During 2005, NSTAR Electric 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. NSTAR Electric has entered into short-term power purchase agreements to meet its entire basic service supply obligation for large customers through March 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, NSTAR Electric entered into agreements ranging in length from three to twelve-months.

In 2004, NSTAR Electric executed agreements to buy-out or restructure twelve of its purchase power agreements that required MDTE approval. These agreements constituted approximately 685 MW of the remaining 800 MW of capacity, and reduced the amount of above-market costs that NSTAR Electric will collect from its customers through its transition charges. As of December 31, 2004, four of these agreements received MDTE approval and were recognized. Two of the four agreements require NSTAR Electric to make monthly payments through December 2008 totaling approximately $80 million. The other two agreements require NSTAR Electric to make monthly payments through September 2011 totaling approximately $125 million. These buy-out/restructuring agreements, once completed, provide no economic benefit to NSTAR Electric and, therefore, the agreements’ contract termination costs were recorded on the accompanying Consolidated Financial Statements.

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

The total amount recognized as of December 31, 2005 and 2004 for obligations relating to eight of the twelve contracts is approximately $764 million and $852 million (present valued); approximately $156 million and $145 million are reflected as a component of current liabilities - energy contracts and approximately $608 million and $707 million as a component of Deferred credits - energy contracts on the accompanying Consolidated Balance Sheets as of December 31, 2005 and 2004, respectively. NSTAR Electric has recorded a corresponding regulatory asset to reflect the full future recovery of these payments through its transition charge. This recognition represents a non-cash increase to assets and liabilities.

Also in January 2005, the MDTE approved the remaining four contract buy-outs with two suppliers that reduced the overall amount of transition costs to be paid for above-market contracts. These contracts are buy-out arrangements whereby NSTAR Electric has made contract termination payments in full release of its obligation under the purchase power agreements. On August 31, 2004, NSTAR Electric filed with the MDTE a proposed financing plan that sought approval for full recovery of these buy-out costs and the issuance of $674.5 million of transition property securitization bonds to provide the funds for these buy-out agreements. The MDTE approved the financing plan in January 2005. On February 15, 2005, the bonds were priced at a weighted average yield of 4.15% and the securitization financing closed on March 1, 2005.

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2. NSTAR Gas Firm Transportation and Storage Agreements

NSTAR Gas purchases transportation, storage and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that bring gas from major producing regions in the U.S., Gulf of Mexico and Canada to the final delivery points in the NSTAR Gas service area. NSTAR Gas purchases all of its gas supply from third-party vendors, primarily under firm contracts with terms of less than one year. NSTAR Gas also utilizes contracts for underground storage and liquefied natural gas facilities to meet its winter peaking demands. During the summer injection season, excess pipeline capacity is used to deliver and store gas in market area storage facilities, located in the New York and Pennsylvania region. Stored gas is withdrawn during the winter season to supplement pipeline supplies in order to meet firm heating demand. NSTAR Gas has firm storage contracts with storage capacity entitlements of nearly 8 billion cubic feet.

NSTAR Gas has various contractual agreements covering the transportation of natural gas and underground natural gas storage facilities, which are recoverable from customers under the MDTE-approved Cost of Gas Adjustment Clause. These contracts expire at various times from 2006 to 2012. NSTAR Gas’ firm contract demand charges associated with firm pipeline transportation and storage capacity contracts in 2005, 2004 and 2003 were approximately $47.7 million, $48.4 million and $50.5 million, respectively. Refer toNote P, “Commitments and Contingencies,” “Energy Supply” section for NSTAR Gas’ firm contract demand charges at current rates under these contracts for the years after 2005.

Note P. Commitments and Contingencies

1. Service Quality Indicators

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

NSTAR 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, each NSTAR utility subsidiary makes a service quality performance filing with the MDTE. Any settlement or rate order that would result in a different liability level from what has been accrued would be adjusted in the period that the MDTE issues an order determining the amount of any such liability.

On March 1, 2005, NSTAR Electric and NSTAR Gas filed their 2004 Service Quality Reports with the MDTE that demonstrated the Companies achieved sufficient levels of reliability and performance; the reports indicate that no penalty was assessable for 2004. On December 30, 2005, the MDTE issued formal approval of this filing.

As of December 31, 2005, NSTAR has determined that for 2005, two of its electric subsidiaries are in a combined penalty position of approximately $0.4 million relating to their applicable service quality indicators. This penalty position is primarily due to service interruptions caused by the severe winter storms experienced earlier in the year. As a result, NSTAR has recorded a liability for this obligation. Since 2001, NSTAR Electric and NSTAR Gas have not been in a penalty position and therefore, the 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. NSTAR cannot predict the outcome or timing of this proceeding.

The Settlement Agreement approved by the MDTE on December 30, 2005, established additional performance measures applicable to NSTAR’s rate regulated subsidiaries. NSTAR Gas shall establish and submit a service quality measure based on separate leaks per mile metrics for bare-steel mains and unprotected, coated-steel

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mains. A specific proposal to implement this performance benchmark shall be submitted to the MDTE for approval by on or before July 1, 2006 and shall be subject to a maximum penalty or incentive of up to $500,000. The Settlement Agreement also establishes, for NSTAR Electric, a performance benchmark relating to poor performing circuits, with a maximum penalty or incentive of up to $500,000.

2. Contractual Commitments

Leases

NSTAR also has leases for facilities and equipment. The estimated minimum rental commitments under non-cancellable capital and operating leases for the years after 2005 are as follows:

(in thousands)
2006	$	19,566
2007		16,462
2008		14,703
2009		13,200
2010		11,230
Years thereafter		35,790
	$	110,951

The total expense for both leases and transmission agreements was $28.3 million in 2005, $27.0 million in 2004 and $25.4 million in 2003, net of capitalized expenses of $1.8 million in 2005, $1.5 million in 2004 and $1.9 million in 2003.

Total rent expense for all operating leases, except those with terms of a month or less, amounted to $17.8 million in 2005, $16.3 million in 2004 and $19.9 million in 2003.

Transmission

As a member of ISO-NE, NSTAR Electric is subject to the terms and conditions of the ISO-NE tariff through February 2010. This obligates NSTAR Electric 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 NSTAR Electric. These payments amounted to $89.6 million, $71.1 million and $62.9 million in 2005, 2004 and 2003, respectively.

Energy Supply

NSTAR Electric 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. NSTAR Electric has entered into a short-term power purchase agreement to meet its entire basic service supply obligation for large customers through March 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. NSTAR Electric 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. NSTAR Electric is currently recovering payments it is making to suppliers from its customers and has financial and performance assurances and financial guarantees in place with those suppliers to protect NSTAR Electric from risk in the unlikely event any of its suppliers encounter financial difficulties or fail to maintain an investment grade credit rating. In connection with certain of these agreements, should, in the unlikely event, an individual NSTAR Electric distribution company receive a credit rating below investment grade, that company potentially could be required to obtain certain financial commitments, including but not limited to, letters of credit. Refer toNote O, “Contracts for the Purchase of Energy” for a further discussion.

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The following represents NSTAR’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
Gas contractual obligations		48		48		47		45		44		67		299
Purchase power buy-out obligations		156		160		162		142		140		206		966
	$	206	$	210	$	211	$	189	$	187	$	294	$	1,297

Electric capacity obligations represent remaining capacity costs of long-term contracts that reflect NSTAR Electric’s proportionate share of capital and fixed operating costs of certain generating units. In 2005, these costs were attributed to 361.6 MW of capacity purchased. Energy costs are paid to generators based on a price per kWh actually received into NSTAR Electric’s distribution system and are included in the total cost. Total capacity purchased in 2005 was 880.7 MW. These contracts expire at various times from 2006 through 2019.

Gas contractual obligations represent agreements covering the transportation of natural gas and underground natural gas storage facilities that are recoverable from customers under the MDTE approved Cost of Gas Adjustment Clause. These contracts expire at various times from 2006 through 2012.

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

3. Electric Equity Investments and Joint Ownership Interest

NSTAR has an equity investment of approximately 14.5% in two companies that own and operate transmission facilities to import electricity from the Hydro-Quebec system in Canada. As an equity participant, NSTAR is required to guarantee, in addition to each company’s own share, the obligations of those participants who do not meet certain credit criteria. At December 31, 2005, NSTAR’s portion of these guarantees amounted to $8.8 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, NSTAR Electric’s reduction of its equity ownership resulting from NEH buy-back of 15,914 shares and NHH buy-back of 94 shares was approximately $0.4 million.

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

The Maine Yankee nuclear unit (MY) was notified on October 3, 2005 by the U.S. Nuclear Regulatory Commission (NRC) that its former plant site has been decommissioned in accordance with NRC procedures. The NRC has amended MY’s license, reducing the land under the license from approximately 179 acres to the 12 acre Independent Spent Fuel Storage Installation (ISFSI) that includes a dry cask storage facility, and marks the first time a commercial nuclear power plant in the United States has been fully decommissioned with all plant

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buildings removed. MY’s amended license will continue to apply to the ISFSI where spent nuclear fuel from the plant’s 23 years of operation is stored. MY remains responsible for the security and protection of the ISFSI and is required to maintain a radiation monitoring program at the site.

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, $149.3 million for YA and $242.5 million for MY. Of these amounts, NSTAR Electric is obligated to pay $72.2 million towards the decommissioning of CY, $20.9 million toward YA, and $9.7 million toward MY. These estimates are recorded in the accompanying Consolidated Balance Sheets as Energy contract liabilities with a corresponding Regulatory asset and do not impact the current results of operations and cash flows. These estimates may be revised from time to time based on information available to the Yankee Companies regarding future costs. The Yankee Companies have received approval from FERC for recovery of these costs and NSTAR expects any additional increases to these costs to be included in future rate applications with the FERC, with any resulting adjustments being charged to their respective sponsors, including NSTAR Electric. NSTAR Electric would recover its share of any allowed increases from customers through the transition charge.

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

CY’s estimated decommissioning costs increased significantly in 2003 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 NSTAR Electric, 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 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. NSTAR Electric NSTAR cannot predict the timing or outcome of the litigation with Bechtel.

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.

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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, NSTAR Electric is obligated to pay $8.8 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. NSTAR Electric cannot predict the timing or the ultimate outcome of these settlement discussions.

4. Financial and Performance Guarantees

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

At December 31, 2005, outstanding guarantees totaled $38.1 million as follows:

(in thousands)
Letters of Credit	$	13,100
Surety Bonds		16,200
Other Guarantees		8,800
Total Guarantees	$	38,100

Letters of Credit

There is a $5.6 million letter of credit for the benefit of a third party, as trustee in connection with the 6.924% Notes of one of NSTAR’s subsidiaries. The letter of credit is available if the subsidiary has insufficient funds to pay the debt service requirements. There have been no amounts drawn under this letter of credit. In addition, during May 2005, NSTAR issued a $7.5 million letter of credit for the benefit of the general contractor on NSTAR’s 345 kV Transmission project. The letter of credit is available if NSTAR’s subsidiary is unable to meet its obligations. As of December 31, 2005, no amounts have been drawn under this letter of credit. The amount of the standby letter of credit was reduced to $4.5 million on February 1, 2006.

Surety Bonds

As of December 31, 2005, certain of NSTAR’s subsidiaries have purchased a total of $1.5 million of performance surety bonds for the purpose of obtaining licenses, permits and rights-of-way in various municipalities. In addition, NSTAR and certain of its subsidiaries have purchased approximately $14.7 million in workers’ compensation self-insurer bonds. These bonds support the guarantee by NSTAR and certain of its subsidiaries to the Commonwealth of Massachusetts required as part of the Company’s workers’ compensation self-insurance program. On January 3, 2006, NSTAR and certain of its subsidiaries executed indemnity agreements to provide additional financial security to its bond company in the form of a contingent letter of credit to be triggered in the event of a downgrade in the future of NSTAR’s Senior Note rating to below BBB by S&P and/or to below Baa1 by Moody’s. These Indemnity Agreements cover both the performance surety bonds and workers’ compensation bonds.

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Other

NSTAR and its subsidiaries have also issued $8.8 million of residual value guarantees related to its equity interest in the Hydro-Quebec transmission companies.

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

5. Environmental Matters

NSTAR subsidiaries face possible liabilities as a result of involvement in several multi-party disposal sites, state-regulated sites or third party claims associated with contamination remediation. NSTAR 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 February 2006 and filed with the Superior Court shortly thereafter. The Settlement is subject to a 90-day public comment period as 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 is within 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, NSTAR had reserves of $10.3 million and $3.9 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 NSTAR’s results of operation, cash flows or its financial position.

NSTAR Gas is participating in the assessment or remediation of certain former manufactured gas plant (MGP) sites and alleged MGP waste disposal locations to determine if and to what extent such sites have been contaminated and whether NSTAR Gas may be responsible for remedial action. The MDTE has approved recovery of costs associated with MGP sites over a 7-year period, without carrying costs. As of December 31, 2005 and 2004, NSTAR recorded a liability of approximately $3.6 million and $3.8 million, respectively, as estimates for site cleanup costs for several MGP sites for which NSTAR Gas was previously cited as a potentially responsible party. A corresponding regulatory asset was recorded that reflects the future rate recovery for these costs.

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 NSTAR’s responsibilities for such sites evolve or are resolved. NSTAR’s ultimate liability for future environmental remediation costs may vary from these estimates. Based on NSTAR’s current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, NSTAR does not believe that these environmental remediation costs will have a material adverse effect on NSTAR’s consolidated financial position, results of operations or cash flows.

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6. 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 NSTAR Electric’s transition and distribution rates effective January 1, 2006 and May 1, 2006, respectively. Effective with the January 1^st date adjustment, NSTAR Electric will freeze its total transition and distribution rates through 2012. Additionally, the Settlement Agreement establishes a 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, NSTAR Electric 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 February 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 $20 million effective January 1, 2006 and by $30 million on May 1, 2006 and are deferred with carrying charges at a rate of 10.88%.

In December 2004, NSTAR Electric 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 each retail electric subsidiary 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.

On October 19, 2005, the MDTE approved a settlement agreement between Cambridge Electric, ComElectric and the Attorney General of the Commonwealth of Massachusetts to resolve issues relating to the reconciliation of transition, standard offer and basic service costs for 2003 and 2004. This settlement agreement had no material effect on NSTAR’s consolidated results of operations, cash flows and financial condition for a reporting period. The reconciliation of transmission costs and revenues was not resolved by settlement and will be decided by the MDTE after a hearing. Settlement discussions with an intervener and the Attorney General of the Commonwealth of Massachusetts are ongoing with respect to Boston Edison’s 2003 and 2004 transmission reconciliation filing. Settlement discussions with the MDTE for the reconciliation of Boston Edison’s 2004 costs for transition, standard offer and basic service have been delayed and will be decided by the MDTE in a future hearing. NSTAR Electric cannot predict the timing or the ultimate out come of these Settlement discussions.

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.

Cambridge Electric and ComElectric filed proposed changes to their OATT with the FERC on March 30, 2005 to provide for consistent application of the OATT among all NSTAR Electric companies. The new tariffs became effective on June 1, 2005; however, the FERC set issues raised in the proceeding for hearing. Settlement discussions with interveners, the Attorney General of Massachusetts, are ongoing. NSTAR cannot predict the timing or ultimate resolution of this proceeding.

b. Legal Matters

In the normal course of its business, NSTAR and its subsidiaries are involved in certain legal matters, including civil litigation. Management is unable to fully determine a range of reasonably possible court-ordered damages,

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settlement amounts, and related litigation costs (“legal liabilities”) that would be in excess of amounts accrued and amounts covered by insurance except for the item disclosed in the Consolidated Financial Statements,Note P, “Commitments and Contingencies.” Based on the information currently available, NSTAR does not believe that it is probable that any such legal liabilities will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal liabilities that may result from changes in circumstances could have a material impact on its results of operations, cash flows and financial condition for a reporting period.

7. Capital Expenditures and Financings

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

(in thousands)	2006		2007-2010
Capital expenditures	$	408,000	$	1,200,000
Long-term debt	$	123,140	$	1,247,857

Capital expenditures for 2006 include the remaining costs related to NSTAR’s 345kV transmission project that amounts to $89 million. The total cost of this project is estimated at approximately $220 million. A significant portion of these costs ($120 million) was incurred in 2005 and the remaining balance will be expended in 2006. In the second quarter of 2005, NSTAR began construction of a switching station in Stoughton, Massachusetts and a 345kV transmission line that will connect the switching station to South Boston. As of December 31, 2005, construction that is part of this project is also in progress on the expansion of two existing substations. 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. This project is expected to be placed in service during the summer of 2006. A substantial portion of the cost of this project will be shared by other utilities in New England based on ISO-New England’s approval and will be recovered by NSTAR through wholesale and retail transmission rates. As of December 31, 2005, NSTAR has contractual construction cost commitments of approximately $17 million related to this project.

As part of NSTAR’s Settlement Agreement approved by the MDTE on December 30, 2005, NSTAR Electric 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 incremental capital additions and 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.

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Report of Independent Registered Public Accounting Firm

To Shareholders and Trustees of NSTAR:

We have completed integrated audits of NSTAR’s December 31, 2005 and December 31, 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its December 31, 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedules

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)2 present fairly, in all material respects, the financial position of NSTAR and its subsidiaries at December 31, 2005 and December 31, 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 Item 15(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 financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and 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 of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established inInternal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established inInternal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

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

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

PricewaterhouseCoopers LLP

/s/ PRICEWATERHOUSECOOPERS LLP

Boston, Massachusetts

February 17, 2006

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

No event that would be described in response to this item 9 has occurred with respect to NSTAR or its subsidiaries.

Item 9A. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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

Management’s Report on Internal Control Over Financial Reporting

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

Under the supervision and with the participation of management, including the principal executive officer and the principal financial officer, NSTAR management has evaluated the effectiveness of its internal control over financial reporting as of December 31, 2005 based on the criteria established in a report entitledInternal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, NSTAR management has evaluated and concluded that NSTAR’s internal control over financial reporting was effective as of December 31, 2005.

Management’s assessment of the effectiveness of NSTAR’s internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm that audited NSTAR’s consolidated financial statements included herewith in the Form 10-K.

Item 9B. Other Information

None

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Part III

The information called for by Part III (Items 10(a), 11, 12, and 14) will be included in NSTAR’s 2006 Proxy Statement (as specified below) to be filed in connection with the Annual Meeting of Shareholders to be held on May 4, 2006 and is incorporated herein by reference. Such Proxy Statement will be filed with the Securities and Exchange Commission on or about March 31, 2006.

Item 10. Trustees and Executive Officers of the Registrant

(a) Identification of Trustees

The information required by this Item is incorporated herein by reference to the sections included in the Company’s 2006 Proxy Statement entitled “Information about the NSTAR Board, Nominees and Incumbent Trustees.”

The information required by this Item with regard to NSTAR’s Corporate Governance Guidelines is incorporated herein by reference to the section included in the Company’s 2006 Proxy Statement entitled “Governance of the Company.”

The information required by the Item with regard to compliance with Section 16(a) of the Securities Exchange Act of 1934 is incorporated herein by reference to the section included in the Company’s 2006 Proxy Statement entitled “Section 16(a) Beneficial Ownership Reporting Compliance.”

Audit, Finance and Risk Management Committee Financial Expert

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

(b) Identification of Officers

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

Item 11. Executive Compensation

The information required by this Item is incorporated herein by reference to the section included in the Company’s 2006 Proxy Statement entitled “Executive Compensation.”

Item 12. Security Ownership of Certain Beneficial Owners and Management

The information required by this item is incorporated herein by reference to the section included in the Company’s 2006 Proxy Statement entitled “Trustee Compensation,” “Common Share Ownership by Trustees and Executive Officers,” and “Change in Control Agreements.”

Item 13. Certain Relationships and Related Transactions

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

Item 14. Principal Accountant Fees and Services

The information required by this Item is incorporated herein by reference to the section included in the Company’s 2006 Proxy Statement entitled “2005-2004 Audit and Related Fees.”

With regard to the Audit, Finance and Risk Management Committee’s policy to pre-approve all audit and non-audit services by the Company’s independent public accountants, the information required by this Item is incorporated herein by reference to the section included in the Company’s 2006 Proxy Statement entitled “Audit, Finance and Risk Management Committee Report.”

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Part IV

Item 15. Exhibits and Financial Statement Schedules

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

1. Financial Statements:

	Page
Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003	49
Consolidated Statements of Comprehensive Income for the years ended December 31, 2005, 2004 and 2003	50
Consolidated Statements of Retained Earnings for the years ended December 31, 2005, 2004 and 2003	50
Consolidated Balance Sheets as of December 31, 2005 and 2004	51
Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003	52
Notes to Consolidated Financial Statements	53
Selected Consolidated Quarterly Financial Data (Unaudited)	15
Report of Independent Registered Public Accounting Firm	87
2.      Financial Statement Schedules:
Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2005, 2004 and 2003	95
3.      Exhibits:
Refer to the exhibits listing beginning below.

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Incorporated herein by reference unless designated otherwise:

NSTAR and its subsidiaries

Exhibit 3	Articles of Incorporation and By-Laws
3.1	Declaration of Trust of NSTAR (dated as of April 20, 1999, as amended April 28, 2005)(NSTAR Form 10-Q for the quarter ended June 30, 2005, File No. 1-14768)
3.2	Bylaws of NSTAR (Annex E to the Joint Proxy Statement/Prospectus, which forms part of the Registration Statement on Form S-4 of NSTAR (No. 333-78285))
3.3	Boston Edison Restated Articles of Organization (Form 10-Q for the quarter ended June 30, 1994, File No. 1-2301)
3.4	Boston Edison Company Bylaws dated April 19, 1977, as amended January 22, 1987, January 28, 1988, May 24, 1988, and November 22, 1989 (Form 10-Q for the quarter ended June 30, 1990, File No. 1-2301)
Exhibit 4	Instruments Defining the Rights of Security Holders, Including Indentures
4.1	Indenture dated as of January 12, 2000 between NSTAR and Bank One Trust Company N.A. (Exhibit 4.1 to NSTAR Registration Statement on Form S-3, File No. 333-94735)
4.2	Votes of the Board of Trustees of NSTAR, dated January 27, 2000, supplementing the Indenture dated as of January 12, 2000 between NSTAR and Bank One Trust Company N. A. (NSTAR Form 10-K for the year ended December 31, 2002, File No. 1-14768)
4.3	Votes of the Board of Trustees of NSTAR, dated September 28, 2000 supplementing the Indenture dated as of January 12, 2000 between NSTAR and Bank One Trust Company N. A. (NSTAR Form 10-K for the year ended December 31, 2002, File No. 1-14768)
4.4	Boston Edison Company Revolving Credit Agreement dated November 15, 2002 (Boston Edison Form 10-Q for the quarter ended March 31, 2003, File No. 1-2301)
4.5	Indenture between Boston Edison Company and the Bank of New York (as successor to Bank of Montreal Trust Company)(Form 10-Q for the quarter ended September 30, 1988, File No. 1-2301)
4.6	Votes of the Pricing Committee of the Board of Directors of Boston Edison Company taken May 10, 1995 re 7.80% debentures due May 15, 2010 (Form 10-K for the year ended December 31, 1995, File No. 1-2301)
4.7	Votes of the Board of Directors of Boston Edison Company taken October 8, 2002 re $500 million aggregate principal amount of unsecured debentures ($400 million, 4.875% due in 2012 and $100 million, Floating rate due in 2005)(Form 8-K dated October 11, 2002, File No. 1-2301)
	Management agrees to furnish to the Securities and Exchange Commission, upon request, a copy of any other agreements or instruments of NSTAR and its subsidiaries defining the rights of holders of any long-term debt whose authorization does not exceed 10% of total assets.
Exhibit 10	Material Contracts
10.1	NSTAR Excess Benefit Plan, effective August 25, 1999 (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768)
10.2	NSTAR Supplemental Executive Retirement Plan, effective August 25, 1999 (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768)
10.3	Special Supplemental Executive Retirement Agreement between Boston Edison Company and Thomas J. May dated March 13, 1999, regarding Key Executive Benefit Plan and Supplemental Executive Retirement Plan (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768)

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10.4	Executive Retirement Plan Agreement between NSTAR and Werner J. Schweiger dated as of February 25, 2002, regarding Supplemental Executive Retirement Plan (NSTAR Form 10-K for the year ended December 31, 2004, File No. 1-14768)
10.5	Amended and Restated Change in Control Agreement between NSTAR and Thomas J. May dated October 23, 2003 (NSTAR Form 10-K for the year ended December 31, 2003, File No. 1-14768)
10.6	NSTAR Deferred Compensation Plan (Restated Effective August 25, 1999) (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768)
10.7	NSTAR 1997 Share Incentive Plan, as amended June 30, 1999 and assumed by NSTAR effective August 28, 2000 (NSTAR Form 10-Q for the quarter ended September 30, 2000, File No. 1-14768)
10.7.1	NSTAR 1997 Share Incentive Plan, as amended January 24, 2002 (NSTAR Form 10-K for the year ended December 31, 2002, File No. 1-14768)
10.8	Amended and Restated Change in Control Agreement between James J. Judge and NSTAR, November 1, 2001. (NSTAR Form 10-K for the year ended December 31, 2001, File No. 1-14768)
10.9	NSTAR Trustee’s Deferred Plan (Restated Effective August 25, 1999), dated October 20, 2000 (NSTAR Form 10-Q for the quarter ended September 30, 2000, File No. 1-14768)
10.10	Master Trust Agreement between NSTAR and State Street Bank and Trust Company (Rabbi Trust), effective August 25, 1999 (NSTAR Form 10-Q for the quarter ended September 30, 2000, File No. 1-14768)
10.11	Amended and Restated Change in Control Agreement between Douglas S. Horan and NSTAR dated November 1, 2001 (NSTAR Form 10-K for the year ended December 31, 2001, File No. 1-14768)
10.12	Amended and Restated Change in Control Agreement between Joseph R. Nolan, Jr. and NSTAR dated November 1, 2001 (NSTAR Form 10-K for the year ended December 31, 2001, File No. 1-14768)
10.13	Amended and Restated Change in Control Agreement between Werner J. Schweiger and NSTAR dated March 1, 2002 (NSTAR Form 10-K for the year ended December 31, 2001, File No. 1-14768)
10.14	Amended and Restated NSTAR Annual Incentive Plan as of January 1, 2003 (NSTAR Form 10-K for the year ended December 31, 2004, File No. 1-14768)
10.15	Boston Edison Company and Entergy Nuclear Generation Company Purchase and Sale Agreement dated November 18, 1998 (Form 10-K for the year ended December 31, 1999, File No. 1-2301)
10.16	Boston Edison Company Restructuring Settlement Agreement dated July 1997 (Form 10-K for the year ended December 31, 1997, File No. 1-2301)
10.17	Agreement and Plan of Merger, as Amended, between BEC Energy and Commonwealth Energy System (Annex A to the Joint Proxy Statement/Prospectus, which forms part of the Registration Statement on Form S-4 of NSTAR (No. 333-78385))
10.18	Amended and Restated Power Purchase Agreement (NEA A PPA), dated August 19, 2004, by and between Boston Edison and Northeast Energy Associates L.P. (filed herewith)
10.19	Amended and Restated Power Purchase Agreement (NEA B PPA), dated August 19, 2004, by and between Boston Edison and Northeast Energy Associates L.P. (filed herewith)
10.20	Amended and Restated Power Purchase Agreement (CECO 1 PPA), dated August 19, 2004, by and between ComElectric and Northeast Energy Associates L.P. (filed herewith)
10.21	Amended and Restated Power Purchase Agreement (CECO 2 PPA), dated August 19, 2004, by and between ComElectric and Northeast Energy Associates L.P. (filed herewith)
10.22	The Bellingham Execution Agreement, dated August 19, 2004 between Boston Edison and ComElectric and Northeast Energy Associates L.P. (filed herewith)

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10.23	Purchase and Sale Agreement, dated June 23, 2004, between Boston Edison and Transcanada Energy Ltd. (Ocean State Power Contract) (filed herewith)
10.24	Termination Agreement, dated June 2, 2004, by and between Cambridge Electric and Pittsfield Generating Company, L. P. (f/k/a Altresco Pittsfield, L.P.) (filed herewith)
10.25	Termination Agreement, dated June 2, 2004, by and between ComElectric and Pittsfield Generating company, L. P. (f/k/a Altresco Pittsfield, L.P.)(filed herewith)
	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 Cambridge Electric, Canal, ComElectric; Boston Edison Company and various other electric utilities operating in New England together with amendments dated August 15, 1978, January 31, 1979 and February 1, 1980. (Exhibit 5(c)13 to New England Gas and Electric Association’s Form S-16 (April 1980), File No. 2-64731)
10.2.1.1	Second Restated NEPOOL Agreement among Boston Edison, Cambridge Electric, Canal and ComElectric and various other electric utilities operating in New England, dated August 16, 2004 (filed herewith)
10.2.1.2	Transmission Operating Agreement among Boston Edison, Cambridge Electric, Canal, ComElectric and various other electric transmission providers in New England and ISO New England Inc., dated February 1, 2005 (filed herewith)
10.2.1.3	Market Participants Service Agreement among Boston Edison, Cambridge Electric, Canal, ComElectric, various other electric utilities operating in New England, NEPOOL and ISO New England Inc., dated February 1, 2005 (filed herewith)
10.2.1.4	Rate Design and Funds Disbursement Agreement among Boston Edison, Cambridge Electric, Canal, ComElectric and various other electric transmission providers in New England, dated February 1, 2005 (filed herewith)
Exhibit 21	Subsidiaries of the Registrant
21.1	(filed herewith)
Exhibit 23	Consent of Independent Accountants
23.1	(filed herewith)
Exhibit 31	Rule 13a - 15/15d-15(e) Certifications (filed herewith)
31.1	Certification Statement of Chief Executive Officer of NSTAR pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification Statement of Chief Financial Officer of NSTAR pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Exhibit 32	Section 1350 Certifications (filed herewith)
32.1	Certification Statement of Chief Executive Officer of NSTAR pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification Statement of Chief Financial Officer of NSTAR pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Exhibit 99	Additional Exhibits
99.1	Annual Reports on Form 11-K for certain employee savings plans for the years ended December 31, 2004, 2003, 2002, 2001 and 2000, as dated June 28, 2005, June 25, 2004, June 30, 2003, June 28, 2002 and June 29, 2001, respectively, (File No. 1-14768)
99.2	MDTE Order approving Settlement Agreement dated December 31, 2005 (NSTAR Form8-K for the event reported December 30, 2005, dated January 4, 2006, File No. 1-14768).

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SCHEDULE II

VALUATION AND QUALIFYING ACCOUNTS

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

(In Thousands)

			Additions
Description	Balance at Beginning of Year		Provisions Charged to Operations		Recoveries		Deductions Accounts Written Off		Balance At End of Year
Allowance for Doubtful Accounts
Year Ended December 31, 2005	$	21,804	$	28,585	$	8,215	$	34,100	$	24,504
Year Ended December 31, 2004	$	23,424	$	24,569	$	7,371	$	33,560	$	21,804
Year Ended December 31, 2003	$	24,379	$	20,509	$	5,949	$	27,413	$	23,424
Tax Valuation Allowance
Year Ended December 31, 2005	$	—	$	—	$	—	$	—	$	—
Year Ended December 31, 2004	$	—	$	—	$	—	$	—	$	—
Year Ended December 31, 2003	$	52,897	$	—	$	—	$	52,897	$	—

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FORM 10-K NSTAR 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.

		NSTAR
		(Registrant)
Date February 17, 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 17th day of February 2006.

Signature	Title
/s/    THOMAS J. MAY         Thomas J. May	Chairman, President, Chief Executive Officer and Trustee
/s/    JAMES J. JUDGE         James J. Judge	Senior Vice President, Treasurer and Chief Financial Officer
/s/    G. L. Countryman         Gary L. Countryman	Trustee
/s/    DANIEL DENNIS         Daniel Dennis	Trustee
/s/    THOMAS G. DIGNAN, JR.         Thomas G. Dignan, Jr.	Trustee
/s/    CHARLES K. GIFFORD         Charles K. Gifford	Trustee
/s/    MATINA S. HORNER         Matina S. Horner	Trustee
/s/    PAUL A. LA CAMERA         Paul A. La Camera	Trustee
/s/    SHERRY H. PENNEY         Sherry H. Penney	Trustee
/s/    WILLIAM C. VAN FAASEN         William C. Van Faasen	Trustee
/s/    G. L. WILSON         Gerald L. Wilson	Trustee

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