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 electric transmission and distribution utility subsidiaries are NSTAR Electric and NSTAR Gas, respectively. NSTAR’s nonutility, unregulated operations include district energy operations primarily through its AES subsidiary, telecommunications operations (NSTAR Com) and a liquefied natural gas

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service company (Hopkinton). Harbor Electric Energy Company, a wholly-owned subsidiary of NSTAR Electric, provides distribution service and ongoing support to its only customer, the Massachusetts Water Resources Authority. Utility operations accounted for approximately 96% of consolidated operating revenues in 2008, 2007 and 2006.

NSTAR consolidates three wholly-owned special purpose subsidiaries, BEC Funding LLC, established in 1999, BEC Funding II, LLC and CEC Funding, LLC, both established in 2004. These entities were created to complete the sale of electric rate reduction certificates to a special purpose trust created by two Massachusetts state agencies. These financing transactions securitized the costs incurred related to the divestiture of generation assets and long-term power contracts.

NSTAR derives its operating 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 electric kWh and natural gas 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 transmission and cost of gas sold expenses and corresponding revenues but will not affect the Company’s net income.

Critical Accounting Policies and Estimates

NSTAR’s discussion and analysis of its financial condition, results of operations and cash flows are based on the accompanying Consolidated Financial Statements, which have been prepared in accordance with 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. The 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 DPU and the FERC. Revenues related to the sale, transmission and distribution of energy 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 a month. Meters that are not read during a given month are estimated and trued-up to actual use in a future period. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and the corresponding unbilled revenue is recorded. Unbilled electric revenue is estimated each month based on daily territory load (customer energy requirements), 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, 2008 and 2007 were $62 million and $60 million, respectively.

The level of 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 revenue during the seasonal periods mentioned above.

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NSTAR’s nonutility 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.

b. Regulatory Accounting

NSTAR follows accounting policies prescribed by GAAP, the FERC and the DPU. As a rate-regulated company, NSTAR’s utility subsidiaries are subject to 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 or a regulatory liability (including cost of removal) based on the probability of current and future cash flows. Regulatory assets represent incurred or accrued costs that have been deferred because they are probable of future recovery from customers. Regulatory liabilities may represent collections from customers that have been deferred because they will be expended in the future or they may relate to the future cost of removal of assets. (Refer to the accompanying Asset Retirement Obligations section of Item 7.) As of December 31, 2008 and 2007, NSTAR has recorded regulatory assets of $2.9 billion and $2.6 billion, and regulatory liabilities of $265 million and $258.9 million, respectively. NSTAR continuously reviews these regulatory 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 any deferred costs ceases to be probable, NSTAR would be required to charge such deferred amounts 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 but not limited to, 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 PBOP liabilities 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. As a result of the requirements of SFAS No. 158, “Employers’ Accounting for Deferred Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements Nos. 87, 88, 106, and 132(R)” (SFAS 158), these factors could have a significant impact on pension and postretirement assets or liabilities recognized.

NSTAR’s Pension Plan and PBOP Plan assets, which partially consist of equity investments, have been affected by recent declines in the overall global equity markets. Fluctuations in the fair value of the Pension Plan and PBOP Plan assets impact the funded status, accounting costs, and cash funding requirements of these Plans. The earnings impact of increased Pension and PBOP costs is mitigated as a result of NSTAR’s DPU-approved pension and PBOP rate adjustment mechanism (PAM). Under the PAM, NSTAR is authorized to recover its pension and PBOP expense through this reconciling rate mechanism. The PAM removes the volatility in earnings that could result from fluctuations in market conditions and plan assumptions.

There were no significant changes to NSTAR’s pension and PBOP benefits in 2008, 2007 and 2006 that had a material impact on recorded pension and PBOP costs. As further described in Note G , “Pension and Other Postretirement Benefits,” to the accompanying Consolidated Financial Statements, NSTAR’s discount rate for the Pension Plan was 6.25% at both December 31, 2008 and 2007, respectively. NSTAR’s discount rate for the PBOP obligation was 6.10% and 6.25% at December 31, 2008 and 2007, respectively. These discount rates align with market conditions and the characteristics of NSTAR’s pension and PBOP obligations. The expected long-term rate of return on both pension plan and PBOP assets for 2008 remained at 9.0%, the same as 2007 and 2006.

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Changes in these assumptions will have an impact on reported pension and PBOP costs in future years in accordance with the cost recognition approaches of SFAS 87 and SFAS 106, respectively. 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.

The following table 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.

Management evaluates the appropriateness of the discount rate through the modeling of a bond portfolio that 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 long-term period. In 2008, NSTAR kept the expected long-term rate of return on plan assets at 9.0% as a result of the prevailing outlook for investment returns. Actuarial assumptions also include an assumed rate for administrative and investment expenses, which have averaged approximately 0.6% for 2008, 2007 and 2006.

The expected long-term rate of return on Plan assets could vary from actual returns as well as the target allocation for investments over time. As such, these fluctuations could impact NSTAR’s capital resources to meet its plan contributions. During 2008, NSTAR contributed $72.6 million to the Pension Plans and $15 million to the PBOP Plan. In 2009 NSTAR expects to contribute $25 million to the Pension Plan and $30 million to the PBOP Plan.

The Pension Protection Act of 2006 (the PPA) requires employers with defined-benefit pension plans to make minimum contributions to fund any shortfall between the assets and liabilities of the plan over a period of seven years. On December 23, 2008, the Worker, Retiree and Employer Recovery Act of 2008 (WRERA) was enacted. WRERA provides relief to single employer pension plans with respect to contribution requirements for the 2008, 2009, and 2010 plan years. Specifically, WRERA reduces the required shortfall to the difference between plan assets and 94% of the plan liabilities for the 2009 plan year (increasing to 96% in 2010). The relief effectively reduces the required amount NSTAR will need to contribute to the pension plan for the 2009 plan year. The Company is in compliance with PPA and WRERA as of December 31, 2008.

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d. Uncertain Tax Positions

Effective January 1, 2007, NSTAR adopted the provisions of FASB Interpretation No. 48 (FIN 48) “Accounting for Uncertainty in Income Taxes, an Interpretation of SFAS No. 109, Accounting for Income Taxes” relating to uncertain tax positions. FIN 48 requires management to use judgment in assessing the potential exposure from tax positions taken that may be challenged by taxing authorities. Management is required to assess the possibility of alternative outcomes based upon all facts available at the reporting date, including in some cases the opinion of independent tax consultants. These estimates could differ significantly from the ultimate outcome. For additional information on uncertain tax positions and estimates used therein, refer to “Income Tax Matters” included in this section of this MD&A.

Investments in Yankee Companies

NSTAR Electric has an equity ownership of 14% in CY, 14% in YA, and 4% in MY, (collectively, the Yankee Companies). CY, YA and MY plant sites have been decommissioned in accordance with NRC procedures. Amended licenses continue to apply to the ISFSI’s where spent nuclear fuel is stored at these sites. CY, YA and MY remain responsible for the security and protection of the ISFSI and are required to maintain radiation monitoring programs at the sites.

Yankee Companies Spent Fuel Litigation

In October, 2006, the U.S. Court of Federal Claims issued a judgment in a spent nuclear fuel litigation, in the amounts of $34.2 million, $32.9 million and $75.8 million for CY, YA and MY, respectively. This judgment in favor of these Yankee companies relates to the alleged failure of the DOE to provide for a permanent facility to store spent nuclear fuel for years prior to 2001 for CY and YA, and prior to 2002 for MY. NSTAR Electric’s portion of the judgment amounts to $4.8 million, $4.6 million and $3 million, respectively. On December 4, 2006, the DOE filed its notice of appeal of the trial court’s decision. As a result, the Yankee Companies have not recognized the damage awards on their books, and therefore, NSTAR Electric has not recognized its portion. On December 14, 2007, the Yankee companies filed complaints against the DOE seeking damages from 2001 for CY and YA, and from 2002 for MY, through a future trial date. On August 7, 2008, a federal appeals court reversed and remanded the U.S. Court of Federal Claims judgment based on an error in the measurement of the award calculation. NSTAR cannot predict the ultimate outcome of this decision on appeal or the subsequent complaints. However, should NSTAR Electric ultimately prevail, proceeds received would be refunded to customers and would not have an earnings impact.

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 Electric’s transition charge filings with the DPU.

Derivative Instruments

Energy Contracts

NSTAR accounts for its energy contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133) and SFAS No. 149, “Amendment of Statement No. 133 on Derivative Instruments and Hedging Activities” (SFAS 149). NSTAR has determined that its electricity supply contracts qualify for, and NSTAR has elected, the normal purchases and sales exception. As a result, these agreements are not reflected on the accompanying Consolidated Balance Sheets. NSTAR has only one significant gas supply contract. This contract is an all-requirements portfolio asset management contract that expires in October 2009. This contract contains market based pricing terms and, therefore, no financial statement adjustments would be required. Gas supply costs incurred related to this contract were $259 million, $224 million

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and $237 million for the years ended December 31, 2008, 2007 and 2006, respectively, and have been recorded to Cost of gas sold on the accompanying Consolidated Statements of Income. Refer to the accompanying Item 7A “Quantitative and Qualitative Disclosures About Market Risk” for a further discussion.

Hedging Agreements

In accordance with a DPU order, NSTAR Gas purchases 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. This practice attempts to minimize the impact of fluctuations in prices to NSTAR’s firm gas customers. These financial contracts do not procure gas supply. These contracts qualify as derivative financial instruments under SFAS 133, as amended by SFAS 149. Accordingly, the fair value of these instruments is recognized on the accompanying Consolidated Balance Sheets as an asset or liability representing amounts due from or payable to the counter parties of NSTAR Gas, as if such contracts were settled as of the balance sheet date. All actual costs incurred or benefits realized are included in the CGAC of NSTAR Gas. As a result, NSTAR Gas records an offsetting regulatory asset or liability for the market price changes, in lieu of recording an adjustment to Other Comprehensive Income. Currently, these derivative contracts extend through April 2010. As of December 31, 2008 and 2007, NSTAR had recorded a liability and a corresponding regulatory asset of $32.9 million and $10.5 million, respectively, to reflect the fair value of these contracts. During the years ended December 31, 2008 and 2007, $16 million and $30 million, respectively, of these financial contracts were settled and were recognized as additional charges to Cost of gas sold on the accompanying Consolidated Statements of Income.

Asset Retirement Obligations

FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143” (FIN 47), “Accounting for Asset Retirement Obligations” (SFAS 143), requires entities to record the fair value of a liability for an 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.

The recognition of an ARO within NSTAR’s regulated utility businesses has no impact on its earnings. In accordance with SFAS 71, for its rate-regulated utilities, NSTAR establishes a regulatory asset to recognize future recoveries through depreciation rates for the recorded ARO. NSTAR has certain plant assets in which this condition exists and is related to both plant assets containing hazardous materials and legal requirements to undertake remediation efforts upon retirement.

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, 2008 and 2007, the estimated amount of the cost of removal included in regulatory liabilities was approximately $265 million and $259 million, respectively, based on the estimated cost of removal component in current depreciation rates. At December 31, 2008, NSTAR has an asset retirement cost in utility plant of $3 million, an asset retirement liability of $26 million and a regulatory asset of $21 million.

New Accounting Standard

SFAS No. 161

On March 19, 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” (SFAS 161) which is intended to improve financial reporting about derivatives and hedging activities by requiring enhanced disclosures. This standard became effective on January 1, 2009. NSTAR anticipates that SFAS 161 will not have a significant impact on its current disclosures.

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Rate and Regulatory Proceedings

a. Rate Structures

Rate Settlement Agreement

Beginning January 1, 2007 and continuing through 2012, the Rate Settlement Agreement establishes annual inflation-adjusted distribution rate increases (SIP of 1.74%, 2.68%, and 2.64% effective January 1, 2009, 2008, and 2007, respectively). These increases are generally offset by an equal and corresponding reduction in transition rates. Uncollected transition costs are deferred and will be collected through future rates with a carrying charge.

Basic Service Rates

Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through Basic Service for those customers who choose not to buy energy from a competitive energy supplier. 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 electric power. As of December 31, 2008, 2007, and 2006, customers of NSTAR Electric had approximately 45%, 47%, and 49%, respectively, of their load requirements provided through Basic Service. NSTAR Electric fully recovers its energy costs through DPU-approved rate mechanisms.

Firm Natural Gas Rates

In addition to delivery service rates, NSTAR Gas’ tariffs include a seasonal CGAC and a LDAC. The CGAC provides for the recovery of all gas supply costs from firm sales 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 DPU. 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%. Changes in the cost of gas supply have no impact on the Company’s earnings due to the CGAC and LDAC rate recovery mechanisms.

b. Service Quality Indicators

SQI are established performance benchmarks for certain identified measures of service quality relating to customer service and billing performance, safety and reliability and consumer division statistics performance for all Massachusetts utilities. NSTAR Electric and NSTAR Gas are required to report annually to the DPU concerning their performance as to each measure and are subject to maximum penalties of up to two percent (two and one-half percent beginning in 2009) of total transmission and distribution revenues should performance fail to meet the applicable benchmarks.

NSTAR monitors its service quality continuously to determine if a liability has been triggered. 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 DPU. 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 DPU issues an order determining the amount of any such liability.

On March 1, 2007, NSTAR Electric and NSTAR Gas filed their 2006 Service Quality Reports with the DPU that demonstrated the Companies achieved sufficient levels of performance. The reports indicate that no penalty was assessable for 2006. The DPU approved both filings but did not approve NSTAR Electric’s benchmarks due to outstanding DPU decisions relating to changes in the calculation of reliability measures for the duration and frequency of service interruptions. On September 25, 2008, the DPU issued an order clarifying these requirements, and NSTAR Electric will file recalculated benchmarks in 2009.

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On February 29, 2008, NSTAR Electric and NSTAR Gas filed their 2007 Service Quality Reports with the DPU that demonstrated the Companies achieved sufficient levels of performance. The NSTAR Electric report did not include 2007 results for reliability measures for the duration and frequency of service interruptions due to the outstanding DPU decisions. The filed reports indicate that no penalty was assessable for 2007 for non-reliability measurements. On May 16, 2008, the DPU issued an order that approved the NSTAR Gas 2007 Service Quality Report, as filed. The September 2008 order clarified the outstanding issues pertaining to calculating reliability measures for the duration and frequency of service interruptions. NSTAR Electric will now file its 2007 Service Quality Report for reliability performance information in 2009.

In addition, the May and September 2008 DPU orders established new requirements for NSTAR Electric performance metrics related to poor performing circuits. These new performance metrics measure circuit performance over a three-year period that commenced on January 1, 2007. NSTAR Electric’s performance level has not been in a penalty position as of December 31, 2008. NSTAR Electric will not be able to determine its final performance related to all of the SQI circuit performance measurements until the end of 2009.

c. Regulatory Matters

Massachusetts Regulatory Environment

On July 2, 2008, the Massachusetts Legislature passed the Green Communities Act (GCA) energy policy legislation designed to substantially increase energy efficiency and the development of renewable energy resources in Massachusetts. The GCA:

The GCA provides for utilities to recover in rates the incremental costs associated with its various mandated programs.

On August 7, 2008, the Massachusetts Global Warming Solutions A ct (GWSA) was enacted. The intention of the GWSA is to reduce greenhouse gas emissions in Massachusetts across multiple sectors of the economy, first by requiring the reporting of carbon dioxide and other greenhouse gas emissions and then requiring the gradual reduction of such greenhouse gas emissions by 80% of 1990 levels over a 40-year period beginning in 2010. Regulations setting forth specific detailed requirements under the GWSA will start with the reporting

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requirements that are presently expected to be established during the second quarter of 2009. By January 1, 2012, the State is expected to adopt regulations establishing a desired level of declining emissions limits for resources that emit greenhouse gases. At this time, NSTAR cannot predict the effect of the GWSA on its future results of operations, financial position, or cash flows.

Electric and Gas Rate Decoupling

On July 16, 2008, the DPU issued an order to all Massachusetts’ electric and gas distribution utility companies that permits them to develop plans to decouple their rates/revenues from sales volumes. This action is intended to encourage utility companies to help their customers reduce energy consumption. Decoupling of rates will allow utility companies to carry out the mandates of the GCA and at the same time collect the adequate level of revenues to maintain the quality and reliability of electric and gas services. This order allows companies to file for recovery of lost base revenues caused by incremental energy efficiency spending until their decoupling rate plans are approved. Once decoupled rate plans are approved, revenues will be set at a level designed to recover the utility companies’ incurred costs plus a return on their investment. This revenue level will be reconciled with actual revenues received from decoupled rates on an annual basis and any over or under collection will be refunded to or recovered from customers in the subsequent year.

NSTAR Electric expects to file for lost base revenues in 2009. The recovery of lost base revenues is not anticipated to have a material impact on earnings as any revenue adjustment mitigates the impact of lower sales resulting from energy efficiency. NSTAR Electric currently does not expect to file for fully decoupled electric rates until after the Rate Settlement Agreement expires in 2012. However, NSTAR Gas may file prior to that date.

Regulatory Proceedings - DPU Safety and Reliability programs (CPSL)

As part of the 2005 rate settlement, NSTAR Electric is allowed to recover incremental spending for the double pole inspection, replacement/restoration and transfer program and the underground electric safety program, which includes stray-voltage remediation and manhole inspections, repairs, and upgrades. Recovery of these Capital Program Scheduling List (CPSL) costs is subject to DPU review and approval. NSTAR Electric incurred incremental costs of $11.1 million and $13.1 million in 2006 and 2007, respectively. This includes incremental operations and maintenance and revenue requirements on capital investments. The final reconciliation of 2006 and 2007 CPSL costs recovery is currently under review by the DPU. The incremental costs for the year 2008 are currently under review by the Company and are estimated to be approximately $15 million. NSTAR anticipates filing with the DPU its final 2008 CPSL cost recovery reconciliation in the second quarter of 2009. NSTAR cannot predict the timing of these pending filings. Should an adverse decision be issued that would disallow CPSL cost recovery, it could have a material adverse impact to NSTAR’s results of operations, financial position, and cash flows.

Wholesale Power Cost Savings Initiatives

The Rate Settlement Agreement encourages NSTAR Electric to continue its efforts to advocate on behalf of customers at the FERC to mitigate wholesale electricity cost inefficiencies that would be borne by regional customers. If NSTAR Electric’s efforts to reduce customers’ costs are successful, it is allowed to retain a portion of those savings as an incentive, as well as recover related litigation costs. Under the terms of the Rate Settlement Agreement, NSTAR Electric was to share in 25% of the savings applicable to its customers. The recovery of NSTAR Electric’s share of benefits is to be collected over three years. As a result of its role in two RMR cases, NSTAR Electric had sought to collect $9.8 million annually for three years and began recognizing and collecting some of these incentive revenues from its customers effective January 1, 2007, subject to final DPU approval. Public hearings were held by the DPU in early 2007 to investigate the basis and support for the incentive payments. After these hearings, NSTAR Electric began discussions with the staff of the newly elected AG and a revised Settlement Agreement was executed on July 23, 2007. This revised Settlement Agreement allowed NSTAR Electric to collect $6.3 million of the savings annually for three years effective January 1, 2007 and it

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stipulated that NSTAR Electric would share 12.5% of the savings applicable to its customers in its future efforts related to new wholesale energy cost savings cases. On February 29, 2008, the DPU issued an order that did not approve the revised Settlement Agreement. The DPU re-established a procedural schedule and final briefs were filed in early May 2008. Through December 31, 2008, $12.6 million has been collected from customers for the Wholesale Power Cost Saving Initiatives.

NSTAR is unable to predict the timing or ultimate outcome of this proceeding. In the event an adverse decision is issued, it would not have a material impact on the Company’s results of operations.

Basic Service Bad Debt Adder

On July 1, 2005, in response to a generic DPU order that required electric utilities in Massachusetts to recover the energy-related portion of bad debt costs in their Basic Service rates, NSTAR Electric increased its Basic Service rates and reduced its distribution rates for those bad debt costs. In furtherance of this generic DPU order, NSTAR Electric included a bad debt cost recovery mechanism as a component of its Rate Settlement Agreement. This recovery mechanism (bad debt adder) allowed NSTAR Electric to recover its Basic Service bad debt costs on a fully reconciling basis. These rates were implemented, effective January 1, 2006, as part of NSTAR Electric’s Rate Settlement Agreement.

On February 7, 2007, NSTAR Electric filed its 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase of its Basic Service bad debt charge-offs. This proposed rate adjustment was anticipated to be implemented effective July 1, 2007. On June 28, 2007, the DPU issued an order approving the implementation of a revised Basic Service rate. However, the DPU instructed NSTAR Electric to reduce distribution rates by the increase in its Basic Service bad debt charge-offs. Such action would result in a further reduction to distribution rates from the adjustment NSTAR Electric made when it implemented the Settlement Agreement. This adjustment to NSTAR Electric’s distribution rates would eliminate the fully reconciling nature of the Basic Service bad debt adder.

NSTAR Electric has not implemented the components of the June 28, 2007 DPU order. Implementation of this order would require NSTAR Electric to write-off a previously recorded regulatory asset related to its Basic Service bad debt costs. NSTAR Electric filed a Motion for Reconsideration of the DPU’s order on July 18, 2007. On December 14, 2007, the Motion for Reconsideration was granted and the DPU reopened the case to hear additional evidence. NSTAR Electric filed additional testimony in April 2008, an evidentiary hearing was held, and briefs were filed in June and early July 2008. NSTAR Electric believes its position is appropriate and that it is probable that it will ultimately prevail. However, in the event that it does not, NSTAR Electric intends to pursue all legal options. As of December 31, 2008, the potential impact to earnings of eliminating the bad debt adder would be approximately $17 million, pre-tax. NSTAR cannot predict the timing of this proceeding.

Regulatory Proceeding - FERC

On July 9, 2007, FERC approved NSTAR Electric’s 2007 proposed consolidated transmission rates as filed on February 14, 2007, subject to refund, pending the conclusion of subsequent proceedings. As a result of these proceedings, NSTAR Electric reached an agreement with the FERC staff, the AG, and a wholesale customer. A final Settlement Agreement was filed on March 12, 2008 and approved by the FERC on June 19, 2008. The implementation of this Settlement Agreement did not have an impact on the Company’s results of operations, financial position, or cash flows.

FERC Transmission ROE

Local Transmission Facilities

Effective retroactive to February 1, 2005, the FERC authorized, for the participating New England Transmission Owners, including NSTAR Electric, a base ROE on transmission facilities of 10.4%. This was increased to 11.14% effective on November 1, 2006. NSTAR earns this ROE on all local transmission facility investments.

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Regional Transmission Facilities

The FERC also authorized a 50 basis point adder on regional facilities for joining a RTO effective February 1, 2005 (the RTO effective date). NSTAR joined ISO-New England on the RTO effective date, thereby qualifying for the adder. This brings the ROE on NSTAR’s regional transmission facilities to 10.9% for the period from February 1, 2005 to October 31, 2006, and 11.64% thereafter. Customers of the ISO-NE participants benefit from this order because it responds to the need to enhance the New England transmission grid to alleviate congestion costs and reliability concerns.

Additional Incentive Adders

Additional incentive adders are decided on a case by case basis according to FERC’s most recent national transmission incentive rules. The FERC may grant a variety of financial incentives, including ROE basis point incentive adders for qualified investments made in new regional transmission facilities. New England projects that were included in ISO-NE’s regional system plan and went into service prior to December 31, 2008 qualified for a 100 basis point ROE adder. This 100 basis point adder, when combined with the FERC’s approved ROEs described above, results in a 12.64% ROE for qualified regional investments. The incentive is intended to promote and accelerate investment in transmission projects that can significantly reduce congestion costs and enhance reliability in the region. NSTAR’s 345 kV Transmission Project, among others, has received this additional incentive adder.

Proposed Transmission Investment

On December 12, 2008, NSTAR Electric, together with Northeast Utilities (NU) (collectively, the Petitioners), filed a joint petition with the FERC for a declaratory judgment that would allow the Petitioners to enter into a bilateral transmission services agreement with Hydro Quebec (HQ) subsidiaries. Under this agreement, the Petitioners would sell 1,200 MW of firm transmission service over a new, participant-funded transmission tie line connecting New England with the HQ system in order for HQ to sell and deliver this same amount of firm power from the HQ system to interested parties in New England for a term of no less than twenty years. This project would provide a competitive source of clean power that is favorable in comparison to current alternatives and provides for an expansion of New England’s transmission system without raising regional transmission rates.

The Petitioners and HQ are negotiating:

These transmission agreements must be approved by the FERC and the Purchase Power Agreement between HQ, NSTAR Electric, and other interested New England entities, must be approved by their appropriate state regulatory agencies. NSTAR Electric anticipates that, if approved by the FERC and the DPU, construction will commence in the 2011 to 2014 timeframe and forecasts that its portion of the construction funding to be approximately $200 million. NSTAR Electric and NU will finance and own this transmission line, while HQ will reimburse NSTAR Electric and NU for the total costs of this project, including an investment return to NSTAR Electric and NU, over twenty years.

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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. 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 or financial condition.

Income Tax Matters

Construction-related Costs

In 2004, NSTAR filed an amended 2002 Federal income tax return to change the method of accounting for certain construction-related overhead costs previously capitalized to plant to the Simplified Service Cost Method (SSCM). Under SSCM, certain costs which were previously capitalized for tax purposes are deducted in the year incurred. NSTAR has claimed additional deductions related to the tax accounting method change in its 2002-2004 returns of $368.9 million. In 2005, NSTAR received formal notification from the IRS that the claim on its amended income tax return would be denied. NSTAR did not receive the requested refund amount due.

In August 2005, the IRS issued Revenue Ruling 2005-53 and Treasury Regulations under Code Section 263A related to the SSCM to curtail these levels of construction-related cost deductions by utilities and others. Under this Regulation, the SSCM is not available for the majority of NSTAR’s constructed property for the years 2005 and forward. NSTAR was required to make a cash tax payment to the IRS of $129.1 million in late 2006 representing the disallowed SSCM deductions taken for 2002-2004 even though the tax refund was never received. This payment will be fully refunded with interest to NSTAR, once this tax position is resolved. As a result of recent developments, as of December 31, 2008, this refund has been recorded as a current refundable income tax on the accompanying Consolidated Balance Sheets; at December 31, 2007, it was recorded as non-current.

RCN Corporation (RCN) Share Abandonment Tax Treatment

On December 24, 2003, NSTAR exited its investment in RCN by formally abandoning its 11.6 million shares of RCN common stock. 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.

Prior to the adoption of FIN 48, it was NSTAR’s tax accounting policy not to recognize tax benefits associated with an uncertain tax position until it is probable that such tax benefit would ultimately be realized. NSTAR determined that it could not conclude that it was probable that the tax deduction related to the abandonment of its RCN investment would ultimately be sustained. Accordingly, NSTAR accrued a tax reserve so as to not recognize the tax benefit of this tax position.

As of January 1, 2007, the potential tax loss was approximately $39.6 million. NSTAR adopted FIN 48 effective January 1, 2007. FIN 48 establishes a tax accounting recognition standard of more-likely-than-not, which is a lower threshold than NSTAR’s previous tax recognition policy of probable. Upon the adoption of FIN 48, NSTAR recognized the entire amount as an adjustment to its January 1, 2007 retained earnings balance. NSTAR cannot predict the timing or ultimate resolution of this tax position.

IRS Appeals and Examinations

As of December 31, 2008, the 2001 through 2007 federal and state tax years remain open. Years 2001 through 2004 (which include the SSCM and RCN Share Abandonment matters) are at the IRS Office of Appeals and

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years 2005 through 2007 are under examination by the IRS. The 2008 Federal income tax return is being examined under the IRS Compliance Assurance Process (CAP). This program accelerates the examination of the return in an attempt to resolve issues before the tax return is filed. NSTAR expects that ongoing IRS audits will not have a material effect on its financial statements. However, the outcome of any audit and the timing of audit settlement are subject to significant uncertainty.

Earnings Outlook

NSTAR is reaffirming its guidance for the year 2009 as follows:

Common Share Dividends

On November 20, 2008, NSTAR’s Board of Trustees declared a quarterly cash dividend of $0.375 per share for shareholders of record on January 9, 2009, payable February 2, 2009. NSTAR’s current annualized rate is $1.50 per share, a 7.1% increase over the previous rate of $1.40 per share. NSTAR expects that the growth rate of its common dividend will continue to be in-line with the growth rate in earnings per share. All future dividend decisions are subject to quarterly dividend declarations based on the Company’s financial position and other relevant considerations at the time.

Results of Operations

The following section of MD&A compares the results of operations for each of the three fiscal years ended December 31, 2008, 2007, and 2006 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.

2008 compared to 2007

Executive Summary

NSTAR achieved several positive performance results in 2008:

Earnings per common share were as follows:

Net income was $237.5 million for 2008 compared to $221.5 million for 2007. Major factors on an after tax basis that contributed to the $16.0 million, or 7.2%, increase include:

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These positive earnings factors were partially offset by:

Significant cash flow events during 2008 include the following:

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NSTAR’s electric energy sales in 2008 were flat primarily due to the unfavorable weather conditions resulting from a cooler summer during 2008 as compared to 2007. In addition, electric sales have been impacted by the downturn in the economy that has resulted in lost sales from commercial office and retail business vacancies, and also by the impact of customer and NSTAR-sponsored conservation measures. The 1.4% decrease in firm gas and transportation sales is due to the milder winter weather that directly impacts residential sales offset by the shift of commercial and industrial customers converting to using natural gas from fuel oil. All gas customer segments are impacted by continued customer conservation efforts.

Weather, higher fuel costs, conservation measures, and economic conditions affect sales to NSTAR’s residential and small commercial customers. Economic conditions, higher fuel costs, and conservation measures affect NSTAR’s large commercial and industrial customers. In terms of customer sector characteristics, industrial sales are less sensitive to weather than residential and commercial sales, which are influenced by temperature extremes. Refer to the “Electric Revenues ” and “Gas Revenues” sections below for more detailed discussions.

NSTAR Electric’s retail peak demand for 2008 was 4,379 MW measured on July 9, 2008. This was 11.7% less than the all-time high peak demand of 4,959 MW reached on August 2, 2006.

Weather Conditions

NSTAR forecasts its electric and natural gas sales based on normal weather conditions. Actual results may vary from those projected due to actual weather conditions, energy conservation, and other factors. Refer to the “Cautionary Statement Regarding Forward-Looking Information” section preceding Item 1. “Business” of this Form 10-K.

The demand for electricity and natural gas is affected by weather conditions. Weather conditions impact electric sales primarily during the summer and, to a greater extent, gas sales during the winter season in NSTAR’s service area. Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur (as further discussed below), particularly when weather patterns experienced are consistently colder or warmer. Also, NSTAR’s electric and gas businesses are sensitive to variations in daily weather, are highly influenced by New England’s seasonal weather variations, and are susceptible to severe storm-related incidents that could adversely affect the Company’s ability to provide energy.

Degree-days measure changes in daily mean temperature levels. A degree-day is a unit measuring how much the outdoor daily mean temperature falls below (in the case of heating) or rises above (in the case of cooling) a base of 65 degrees. The comparative information below relates to heating and cooling degree-days for the years 2008 and 2007 and the number of heating and cooling degree-days in a “normal” year as presented by a 30-year average. NSTAR uses the “normal 30-year average” degree-days data to compare current temperature readings to a baseline or “normal” period, that is recalculated every ten years for the preceding 30 years (currently 1971-2000), as collected at the Worcester, Massachusetts airport and Boston’s Logan Airport for heating degree-day data and cooling degree-day data, respectively. Weather conditions during the three months ended March 31, 2008 and June 30, 2008 measured by heating degree-days were 4.3% and 14.1% lower/warmer for 2008 as compared to 2007, unfavorably impacting gas revenues. Weather conditions during the three months ended September 30, 2008 measured by cooling degree-days were 10.4% lower/cooler for 2008 as compared to 2007, unfavorably impacting electric revenues. Refer to the “Electric Revenues” and “Gas Revenues” sections below for more detailed discussions.

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Electric Revenues

NSTAR’s largest earnings sources are the revenues derived from distribution and transmission rates approved by the DPU and FERC. Electric retail distribution revenues primarily represent charges to customers for recovery of the Company’s capital investment, including a return component, and operation and maintenance costs related to its electric distribution infrastructure. The transmission revenue component represents charges to customers for the recovery of similar costs to move the electricity over high voltage lines from the generator to the Company’s substations.

The increase of $6.3 million, or 0.7%, in retail distribution and transmission revenues primarily reflects:

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These increases were partially offset by:

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 Basic Service. These revenues are fully reconciled to the costs incurred and have no impact on NSTAR’s consolidated net income. Energy, transition, and other revenues also reflect revenues related to the Company’s ability to effectively reduce stranded costs (incentive entitlements), rental revenue from electric property, and annual cost reconciliation true-up adjustments. The $70.4 million increase in energy, transition, and other revenues is primarily attributable to the increased recovery of energy supply costs. Uncollected transition charges as a result of the reductions in transition rates are being deferred and collected through future rates with a carrying charge.

Gas Revenues

Firm and transportation gas revenues primarily represent charges to customers for the Company’s recovery of costs of its capital investment in 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 the Company’s service area. The $7.1 million decrease in firm and transportation revenues is primarily attributable to warmer winter weather conditions offset by customers converting to natural gas from alternate fuel sources as a result of higher energy price concerns. These factors resulted in the decrease in sales volumes of 1.4% through December 31, 2008.

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 energy supply and other revenues increase of $0.4 million primarily reflects an increase in the cost of gas supply offset by the lower sales demand. These revenues are fully reconciled with the costs 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 derived from NSTAR’s district energy and telecommunications operations. Unregulated revenues were $152.1 million in 2008 compared to $138.5 million in 2007, an increase of $13.6 million, or 9.8%. The increase in unregulated revenues is primarily the result of the absence of a provision for a potential customer refund recorded in 2007 and increases in energy sales, prices and higher ISO-NE capacity revenues during 2008.

Operating Expenses

Purchased power and transmission costs were $1,430.4 million in 2008 compared to $1,390.6 million in 2007, an increase of $39.8 million, or 2.9%. This increase in expense reflects $34.8 million of higher transmission costs and higher Basic Service and other energy supply costs of $5 million. 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 NSTAR Electric’s energy supply expense have no impact on earnings.

Cost of gas sold , representing NSTAR Gas’ supply expense, was $372.4 million in 2008 compared to $375.8 million in 2007, a decrease of $3.4 million, or 0.9%. The decrease in this cost primarily reflects the 1.4% decrease in firm gas sales and the lower settlement of hedging contracts during the current year that decreased

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expenses by $14.8 million, partly offset by 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 and therefore changes in the amount of energy supply expenses have no impact on earnings.

Operations and maintenance expense was $459.1 million in 2008 compared to $446.8 million in 2007, an increase of $12.3 million, or 2.8%. This increase primarily relates to higher labor and labor related costs, higher than planned insurance and claims costs, higher advertising costs, and higher storm-related costs.

Depreciation and amortization expense was $379.8 million in 2008 compared to $369.6 million in 2007, an increase of $10.2 million or 2.8%. The increase primarily reflects higher depreciable distribution and transmission plant in service. The increase in transmission plant is primarily related to the in-service of NSTAR’s 345 kV project in December 2008.

DSM and renewable energy programs expense was $73.3 million in 2008 compared to $70.9 million in 2007, an increase of $2.4 million, or 3.4%, which is consistent with the collection of conservation and renewable energy revenues. These costs are in accordance with program guidelines established by the DPU and are collected from customers on a fully reconciling basis plus an incentive return.

Property and other taxes were $100.4 million in 2008 compared to $93.7 million in 2007, an increase of $6.7 million, or 7.2%, reflecting higher overall property investments and higher tax rates.

Income tax expense attributable to operations was $143.9 million in 2008 compared to $130.4 million in 2007, an increase of $13.5 million, or 10.4%, primarily reflecting the higher pre-tax operating income in 2008.

Other income (deductions):

Other income, net was approximately $9.0 million in 2008 compared to $10.1 million in 2007, a decrease of $1.1 million. The decrease reflects lower after-tax earnings from the Company’s equity investments and lower interest and dividend income. These factors were partially offset by after-tax proceeds of $2.9 million resulting from an environmental site insurance settlement.

Other deductions, net was approximately $3.6 million in 2008 compared to $3.0 million in 2007, an increase of $0.6 million. The increase in deductions primarily reflects an after-tax loss on insurance policies investments of $1.5 million, partially offset by lower charitable contributions in 2008 as compared to 2007.

Interest charges (income):

Long-term debt and transition property securitization certificate interest charges were $161.5 million in 2008 compared to $155 million in 2007, an increase of $6.5 million, or 4.2%. The increase in interest charges reflects:

This increase was partially offset by:

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Short-term debt and other interest charges (income), net were $7.7 million of net interest income in 2008 compared to $16.3 million of net interest expense in 2007, a change of $24 million, or 147%. The change in short-term and other interest charges (income) reflects:

These decreases were offset by:

2007 compared to 2006

Executive Summary

NSTAR achieved several positive performance results in 2007:

Earnings per common share were as follows:

Net income was $221.5 million for 2007 compared to $206.8 million for 2006. Major factors (after tax) that contributed to the $14.7 million, or 7.1%, increase included:

These increases in earnings factors were partially offset by:

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Significant cash flow events during 2007 included the following:

Nonmonetary Transactions - 2006

In 2006, NSTAR’s unregulated subsidiary, AES, recognized the impact of several nonmonetary transactions. As part of an agreement executed with a vendor, AES received new equipment with a fair value of $4.1 million, at no cost, to compensate AES for incremental costs incurred resulting from equipment installation problems experienced during 2003 and 2004. This resulting nonmonetary gain, representing the fair value of the new equipment, was primarily recognized as a reduction in purchased power expense on the accompanying Consolidated Statements of Income.

In addition, in separate transactions in 2006, two agreements were executed between AES and other parties, which required AES to relinquish its rights under existing easements and other assets owned by AES located on development sites. In exchange, AES received title to new steam and chilled water pipelines with greater capacity and replacement easements. As a result of these new assets, AES anticipates achieving higher future sales. Therefore, the transactions were recorded at the fair value of the assets received and resulted in a $5.5 million nonmonetary gain recorded to other income on the accompanying Consolidated Statements of Income.

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Electric residential and commercial customers represented approximately 30% and 62%, respectively, of NSTAR’s total electric sales mix in 2007 and provided 40% and 54% of distribution and transmission revenues, respectively. Gas residential and commercial customers represented approximately 47% and 36%, respectively, of NSTAR’s total gas sales mix in 2007. Industrial sales were primarily influenced by national and local economic conditions. Refer to the “Electric Revenues” and “Gas Revenues” sections below for a more detailed discussion.

The 1.8% or 375,214 MWh energy sales increase in 2007 primarily reflected colder winter temperatures and warmer weather in late August and September of 2007. NSTAR Electric’s retail peak demand for 2007 was 4,554 MW measured on August 3, 2007. This was 8.2% less than the all-time high peak demand of 4,959 MW reached on August 2, 2006. Industrial sales continued to lag due to the weak manufacturing segment of the economy. The 12.7% increase in firm gas and transportation sales was due to the colder winter weather during 2007 and the shift of commercial and industrial customers that returned to using natural gas from fuel oil. All gas customer segments showed positive sales growth despite continued customer conservation efforts. However, even with the higher energy usage, revenues and the cost of that energy (which is also included in revenues) reflected the sustained high levels in global energy costs.

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