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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.



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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 to Note N of the accompanying Consolidated Financial Statements in Item 8, Financial Statements and
Supplementary Data for specific financial information related to NSTARs electric utility, 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.



11



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##### Table of Contents

|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 atDecember 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 securitiesto be issued uponexercise ofoutstanding options |  | Weighted averageexercise price ofoutstandingoptions |       | Number ofsecurities remainingavailable forfuture issuanceunder equitycompensation 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 ofCommon SharesPurchased |  | Average PricePaid 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)
|                                          |  | OperatingRevenues |         | 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.



15



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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 accompanying Notes to Consolidated Financial Statements and NSTAR encourages a review of these Notes.



Critical Accounting Policies and Estimates



NSTARs discussion and analysis of its financial condition, results of operations and cash flows are based upon the accompanying Consolidated Financial
Statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of these Consolidated Financial Statements required management to make estimates and 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 in Note 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 inAssumption |  | Impact onProjected BenefitObligationIncrease/(Decrease) |         |   | Impact on 2005 CostIncrease/(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  |    |  | Normal30-YearAverage
|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  |    |  | Normal30-YearAverage
|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 |   | YearsThereafter |  | 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 |   | CarryingAmount |  | 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.



49



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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.



50



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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.



51



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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.



52



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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 to Note 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 to
Note E to these Consolidated Financial Statements for more information on regulatory assets.



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



3. Revenues



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                  |  | DepreciableLife
|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 accompanying Note J to Consolidated Financial
Statements. NSTAR applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB 25) and related Interpretations in accounting for this plan.
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 to Note 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.



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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 |        
|                                           |  | PreviouslyReported           |         | As Adjusted |   | Effect ofChange | 
|Consolidated Income Statement              |  |                              |         |             |   |                 |  |   |          |  
|Depreciation and amortization              |  | $                            | 246,944 |             | $ | 254,852         |  | $ | 7,908    |  
|Income taxes                               |  |                              | 116,238 |             |   | 108,330         |  |   | (7,908   | )
|                                           |  |                              |        
|                                           |  | PreviouslyReported           |         | As Adjusted |   | Effect ofChange | 
|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            |        
|                                           |  | PreviouslyReported           |         | As Adjusted |   | Effect ofChange | 
|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 |        
|                                           |  | PreviouslyReported           |         | As Adjusted |   | Effect ofChange | 
|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 |        
|                                     |  | PreviouslyReported           |         | AsAdjusted |   | Effect ofChange | 
|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 to Note 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 to Note 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 to Note 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 to Note 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 to Note 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 31stfor 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 31stas 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 31stfor 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 31stas well as the Plans target percentages and the permissible
range:



|                  |      |             |   |      |                   |   |  |                    |   |           |           |  |                      
|----------------- | ---- | ----------- | - | ---- | ----------------- | - |  | ------------------ | - | --------- | --------- |  | ---------------------
|Asset Category    |      | Plan Assets |   |      | TargetPercentages |   |  | 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:



|                                   |  |              |   |  |                              |       |              |           |   |                              |   |              |  |           |                              |  |   |      
|---------------------------------- |  | ------------ | - |  | ---------------------------- | ----- | ------------ | --------- | - | ---------------------------- | - | ------------ |  | --------- | ---------------------------- |  | - | -----
|                                   |  | 2005Activity |   |  | WeightedAverageExercisePrice |       | 2004Activity |           |   | WeightedAverageExercisePrice |   | 2003Activity |  |           | WeightedAverageExercisePrice
|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 ofExercise Prices |  | NumberOutstanding |  | WeightedAverageRemainingContractualLife (Years) |  | WeightedAverageExercisePrice |       | NumberOutstanding |         | WeightedAverageExercisePrice
|$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



72



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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 ofShares |  | TotalPar Value |         | Premium onCommonShares |  
|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 |        | RedemptionPrice/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.



73



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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)                                        |  | CarryingAmount |           | Fair Value |   | CarryingAmount |  | 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 to Note 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 to Note
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 |   | YearsThereafter |  | 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 1stdate 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 in
Internal 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 in Internal 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 entitled Internal 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 in Item
4A of this Form 10-K.



|Item 11. | Executive Compensation
|-------- | ----------------------



The information required by this Item is incorporated herein by reference to the section included in the Companys 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 atBeginningof Year |        | ProvisionsCharged toOperations |   | Recoveries |  | DeductionsAccountsWritten Off |       | BalanceAt Endof 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. MAYThomas J. May                 |  | Chairman, President, Chief Executive Officer and Trustee    
|                                                  | 
|/s/    JAMES J. JUDGEJames J. Judge               |  | Senior Vice President, Treasurer and Chief Financial Officer
|                                                  | 
|/s/    G. L. CountrymanGary L. Countryman         |  | Trustee                                                     
|                                                  | 
|/s/    DANIEL DENNISDaniel Dennis                 |  | Trustee                                                     
|                                                  | 
|/s/    THOMAS G. DIGNAN,
JR.Thomas G. Dignan,
Jr. |  | Trustee                                                     
|                                                  | 
|/s/    CHARLES K.
GIFFORDCharles K.
Gifford       |  | Trustee                                                     
|                                                  | 
|/s/    MATINA S.
HORNERMatina S.
Horner           |  | Trustee                                                     
|                                                  | 
|/s/    PAUL A. LA
CAMERAPaul A. La
Camera         |  | Trustee                                                     
|                                                  | 
|/s/    SHERRY H.
PENNEYSherry H.
Penney           |  | Trustee                                                     
|                                                  | 
|/s/    WILLIAM C. VAN
FAASENWilliam C. Van
Faasen |  | Trustee                                                     
|                                                  | 
|/s/    G. L. WILSONGerald L. Wilson               |  | Trustee                                                     



96