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. 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. NSTAR’s nonutility, unregulated operations include telecommunications operations (NSTAR Com) and a liquefied natural gas service company (Hopkinton). Utility operations accounted for approximately 99% of consolidated operating revenues of continuing operations in 2009, 2008, and 2007.

NSTAR consolidates three wholly-owned special purpose subsidiaries, BEC Funding LLC, BEC Funding II, LLC and CEC Funding, LLC. 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, transmission, and energy efficiency services to customers. NSTAR’s earnings are impacted by fluctuations in unit sales of electric kWh and natural gas MMbtu, which have an effect on 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 have an impact on purchased power and transmission and cost of gas sold expenses, but will not affect the Company’s net income as the Company recognizes a corresponding change in revenues.

Discontinued Operations

On December 21, 2009, NSTAR announced an agreement to sell its wholly-owned subsidiary, Medical Area Total Energy Plant, Inc. (MATEP). MATEP provides steam, chilled water service, and electricity under long-term contracts to several hospitals, medical research and biotechnology centers, and teaching institutions in the Longwood Medical Area of Boston. The sale is at a price of approximately $320 million in cash and is subject to certain federal and local regulatory approvals. The purchase price is subject to certain closing adjustments related to changes in working capital, interest, and other adjustments. In connection with the sale, NSTAR will retire MATEP’s debt.

MATEP’s principal asset is a cogeneration plant that produces electricity, steam and chilled water, and a distribution system that delivers these products to its customers. MATEP has approximately 85 employees.

The sale is expected to close towards the end of the first quarter or early part of the second quarter of 2010. Net proceeds from the transaction are anticipated to be used to reduce NSTAR’s capitalization.

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

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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

Electric and gas revenues are based on 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 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, aggregate 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 applicable customer rates. Accrued unbilled revenues recorded in the accompanying Consolidated Balance Sheets as of December 31, 2009 and 2008 were $67 million and $62 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 Gas’ customer base uses natural gas for heating purposes. As a result, NSTAR records a higher level of revenue during the seasonal periods mentioned above.

NSTAR’s nonutility revenues are recognized when services are rendered. 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. In addition, NSTAR and its subsidiaries are subject to the accounting and reporting requirements of the SEC. As rate-regulated companies, NSTAR’s utility subsidiaries are subject to the application of an accounting standard for rate-regulated entities, ASC 980, Regulated Operations , that considers the effects of regulation resulting from differences in the timing of their recognition of certain revenues and expenses from those of other businesses and industries. NSTAR’s distribution and transmission businesses are subject to rate-regulation that is based on cost recovery and meets the criteria for application of ASC 980. 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 and Cost of Removal” section of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” ) As of December 31, 2009 and 2008, NSTAR has recorded regulatory assets of $2.6 billion and $2.9 billion, and regulatory liabilities of $270 million and $265 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 earnings. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.

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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.

Changes in pension and PBOP assets and 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. However, 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 trends 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 substantially mitigated by NSTAR’s DPU-approved pension and PBOP rate adjustment mechanism. Under the PAM, NSTAR recovers its pension and PBOP expense through a reconciling rate mechanism. The PAM removes the volatility in earnings that could result from fluctuations in market conditions and plan experience.

There were no significant changes to NSTAR’s pension and PBOP benefits in 2009, 2008, and 2007. As further described in Note H , “Pension and Other Postretirement Benefits,” in the accompanying Notes to the Consolidated Financial Statements, NSTAR’s discount rate for the Pension Plan obligation was 5.85% and 6.25% at December 31, 2009 and 2008, respectively. NSTAR’s discount rate for the PBOP obligation was 6.00% and 6.10% at December 31, 2009 and 2008, respectively. These discount rates align with market conditions and the anticipated cash flow characteristics of NSTAR’s pension and PBOP obligations. The expected long-term rate of return on both pension plan and PBOP assets for 2009 remained at 9.0%, the same as 2008 and 2007. Changes in these assumptions have an impact on reported pension and PBOP costs and obligations.

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

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Management evaluates the appropriateness of the discount rate through the modeling of a bond portfolio that approximates the Plan liabilities. 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. The expected long-term rate of return on Plan assets could vary from actual year-to-year returns. The target allocation for investments may vary from the actual allocation at any particular time. During 2009, NSTAR contributed $125 million to the Pension Plans and $30 million to the PBOP Plan. In 2010 NSTAR expects to contribute $25 million to the Pension Plan and $35 million to the PBOP Plan.

The Pension Protection Act of 2006 (the PPA) generally requires employers with defined-benefit pension plans to make minimum contributions to fund any shortfall between the assets and liabilities of the plan (as defined by the PPA) over a period of seven years. On December 23, 2008, the Worker, Retiree and Employer Recovery Act of 2008 (WRERA) was enacted, providing relief to single employer pension plans with respect to contribution requirements for the 2009 and 2010 plan years. The Company is in compliance with the funding requirements of PPA and WRERA as of December 31, 2009.

d. Uncertain Tax Positions

Accounting for uncertain tax positions 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. 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 Connecticut Yankee Atomic Power Company (CY), 14% in Yankee Atomic Electric Company (YA), and 4% in Maine Yankee Atomic Power Company (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 Department of Energy (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 (DOE Phase I Damages). NSTAR Electric’s portion of the Phase I judgments amounts to $4.8 million, $4.6 million, and $3 million, respectively. On July 1, 2009, the Yankee Companies filed for additional damages related to the alleged failure of the DOE to provide for a permanent facility to store spent nuclear fuel for the years from January 2002 through December 2008 for CY and YA, and from January 2003 through December 2008 for MY (DOE Phase II Damages). This phase of the spent nuclear fuel litigation specifies damages in the amounts of $135.4 million, $86.1 million, and $43 million for CY, YA, and MY, respectively. Claim amounts applicable to NSTAR Electric are $19 million, $12 million, and $1.7 million, respectively.

NSTAR cannot predict the ultimate outcome of these pending decisions for trial, appeal or the potential subsequent complaints. However, should the Yankee Companies ultimately prevail, NSTAR Electric’s share of the proceeds received would be refunded to its customers.

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.

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Derivative Instruments

Energy Contracts

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 essentially an all-requirements portfolio asset management contract that expires in October 2011. This contract contains market based pricing terms and, therefore, no financial statement adjustments to mark the contracts to market are required. Gas supply costs incurred related to the gas asset management contract were approximately $177 million, $259 million, and $224 million for the years ended December 31, 2009, 2008, and 2007, 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.

Gas 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. 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 counterparties 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 2011. As of December 31, 2009 and 2008, NSTAR had recorded a liability and a corresponding regulatory asset of $1.7 million and $32.9 million, respectively, to reflect the fair value of these contracts. During the years ended December 31, 2009, 2008, and 2007, $47 million, $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 and Cost of Removal

The fair value of a liability for an asset retirement obligation (ARO) is recorded 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. 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.

At December 31, 2009 and 2008, NSTAR had recorded asset retirement cost liabilities of $30 million and $23 million, respectively, which approximates the current cost for NSTAR to meet its legal or contractual obligations to perform actions at some point after the retirement of an asset. This amount is included in Deferred credits and other liabilities: Other on the accompanying Consolidated Balance Sheets.

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, 2009 and 2008, the estimated amount of the cost of removal included in regulatory liabilities was

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approximately $270 million and $265 million, respectively, based on the estimated cost of removal component in current depreciation rates. This represents the cumulative amounts collected from customers for cost of removal, but not yet expended.

New Accounting Standards Updates

Variable Interest Entities

Amended consolidation guidance applicable to variable interest entities will be effective for NSTAR beginning in fiscal year 2010. The Company does not anticipate that this authoritative guidance will have an effect on the Company’s existing contractual and business relationships and how they are reported in the consolidated financial statements.

Rate and Regulatory Proceedings

a. Rate Structures

Rate Settlement Agreement

NSTAR Electric is currently operating under a DPU-approved Rate Settlement Agreement (“Rate Settlement Agreement”) that expires December 31, 2012. From 2007 through 2012, the Rate Settlement Agreement establishes for NSTAR Electric, among other things, annual inflation-adjusted distribution rates that are generally offset by an equal and corresponding reduction in transition rates. The increase adjustment will be 1.32% effective January 1, 2010; and corresponding adjustments were 1.74%, 2.68%, and 2.64% effective January 1, 2009, 2008, and 2007, respectively. Uncollected transition charges as a result of the reductions in transition rates are deferred and collected through future rates with a carrying charge. The Rate Settlement Agreement implemented a 50% / 50% earnings sharing mechanism based on NSTAR Electric’s distribution return on equity (excluding incentives) should it exceed 12.5% or fall below 8.5%. Should the return on equity fall below 7.5%, NSTAR Electric may file a request for a general rate increase. NSTAR Electric did not exceed the 12.5%, or fall below the 8.5% distribution return on equity during 2009, 2008 or 2007.

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, 2009, 2008, and 2007, customers of NSTAR Electric had approximately 43%, 45%, and 47%, 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

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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 and one-half percent 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.

NSTAR Electric filed its 2007 Service Quality Reports with the DPU that demonstrated the Company achieved sufficient levels of service performance. On January 13, 2010, the DPU approved the 2007 Service Quality Report and agreed performance levels were sufficient. Therefore, no penalties were assessed.

Service Quality reports for both NSTAR Gas and NSTAR Electric for 2008 have been filed with the DPU. The NSTAR Gas report has been approved and the NSTAR Electric report is under review. Based on the reports filed, no penalties were assessable for the performance year.

NSTAR Electric and NSTAR Gas service quality performance levels for 2009 were not in a penalty situation and the final performance reports are anticipated to be filed during the first quarter of 2010.

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 allows 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

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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 started with the establishment of 1990 Baseline and 2020 Business as Usual Projection during 2009. By January 2011, 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.

Long-Term Renewable Energy Contracts

In accordance with the requirements of the GCA, in January, 2010 NSTAR Electric along with other Massachusetts investor-owned utilities began to solicit bids for renewable energy and renewable energy certificates for approximately 1.5% of total annual load for between ten and 15 year periods. The evaluation of supplier bids will be weighted primarily towards price factors, but also by non-price factors such as reliability and financial stability. All contracts must be approved by the DPU.

Electric and Gas Rate Decoupling

On July 16, 2008, the DPU issued an order to all Massachusetts’ electric and gas distribution utility companies that requires 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.

This revenue adjustment mitigates the impact of lower sales resulting from incremental energy efficiency programs. 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 Rate Settlement Agreement, 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 million, $13 million, and $15 million in 2006, 2007 and 2008, 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 2009 are currently under review by the Company and are estimated to be approximately $16 million. NSTAR awaits the results of the 2006 and 2007 filings from the DPU prior to submitting the final 2008 and 2009 CPSL cost recovery reconciliations with the DPU. NSTAR cannot predict the timing of a DPU order related to these pending filings. Should an adverse decision be issued which disallows a significant portion of 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 includes incentives to encourage NSTAR Electric to continue its efforts to advocate on behalf of customers at the FERC to mitigate wholesale electricity cost inefficiencies that would be

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borne by regional customers. 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 collecting some of these incentive revenues from its customers effective January 1, 2007, subject to final DPU approval. Through December 31, 2009, approximately $18.9 million had been collected from customers for the Wholesale Power Cost Savings Initiatives.

On November 30, 2009, DPU denied NSTAR Electric’s petition. NSTAR Electric must refund the $18.9 million already collected from customers. The DPU order had no impact on earnings as the Company did not reflect the amounts collected in revenues.

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 cost of 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) allows 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 the DPU does not rule in its favor, NSTAR Electric intends to pursue all legal options. As of December 31, 2009, the potential impact to earnings of eliminating the bad debt adder would be approximately $20.8 million, pre-tax. NSTAR cannot predict the timing of this proceeding.

FERC Transmission ROE

Local Transmission Facilities

For participating New England Transmission Owners, including NSTAR Electric, a base ROE on transmission facilities of 11.14% has been approved by FERC. NSTAR earns this ROE on all local transmission facility investments.

Regional Transmission Facilities

The FERC authorized an ROE on NSTAR’s regional transmission facilities of 11.64%.

Additional Incentive Adders

Additional incentive adders are available and are decided on a case by case basis in accordance with the FERC’s most recent national transmission incentive rules. The FERC may grant a variety of financial incentives,

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including ROE basis point incentive adders for qualified investments made in new regional transmission facilities. 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 completed in phases through December 2008, among others, has received this additional incentive adder.

Other

Energy Efficiency Plans

NSTAR Electric and NSTAR Gas are required to administer demand-side management energy efficiency programs. The GCA directs electric and gas distribution companies to develop three-year energy efficiency plans. The first three-year plan effective in 2010 is expected to lead to a significant expansion of energy efficiency activity in Massachusetts. Like the historical programs, the new three-year plans may include financial incentives based on energy efficiency program performance. In addition, the DPU has stated that it will permit distribution companies that do not yet have rate decoupling mechanisms in place to implement lost base revenue rate adjustment mechanisms that will partially offset reduced distribution rate revenues as a result of successful energy efficiency programs.

During 2009, NSTAR Electric incurred Energy Efficiency expenses of approximately $80.1 million, inclusive of program administrator incentives. NSTAR Electric has filed its 2010 Energy Efficiency Plan and anticipates that the program will amount to about $122 million in spending. The 2010 plan was approved by DPU on January 28, 2010.

During 2009, NSTAR Gas incurred Energy Efficiency expenses of approximately $8.2 million, inclusive of program administrator incentives. NSTAR Gas has filed its 2010 Energy Efficiency Plan and anticipates that the program will amount to about $16.4 million in spending, subject to DPU approval. The 2010 plan was approved by DPU on January 28, 2010.

American Recovery and Reinvestment Act of 2009 (ARRA)

The American Recovery and Reinvestment Act of 2009 (ARRA) provides resources for government-funded spending in several energy-related areas that have relevance to NSTAR, including energy efficiency, smart grid funding, renewable energy financing and transmission projects. These initiatives are largely directed through federal and state agencies and not-for-profit public agencies. NSTAR continues to evaluate the impact of this legislation on its business initiatives in these areas. Any action will require regulatory approval.

In August 2009, NSTAR Electric applied for Federal grants for its Smart Grid Programs. The requested funding represents 50% of the estimated total project costs. On October 27, 2009 and November 25, 2009, NSTAR Electric received notice from the U.S. Department of Energy (DOE) that it had been awarded grants of approximately $18 million for three projects related to distribution automation, smart metering and renewable energy inter-connections proposals. NSTAR Electric anticipates that most of the remaining costs not recovered through the grant process will be recovered from customers. These projects are anticipated to enhance information technology, communications and monitoring functions and improve reliability and efficiency on NSTAR Electric’s distribution network.

Proposed Transmission Investment

NSTAR, together with Northeast Utilities (NU) (collectively, the Petitioners), filed and received approval on 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

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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:

The transmission service agreement must be approved by the FERC and the Power Purchase Agreement between HQ, NSTAR and other interested New England entities must be approved by their appropriate state regulatory agencies. NSTAR anticipates that, if approved by the FERC and the DPU, construction will commence in the 2011 timeframe and is targeted for completion in 2015. NSTAR’s portion of the construction funding is estimated to be approximately $225 million. NSTAR and NU will finance and own this transmission line, while HQ will reimburse NSTAR and NU for the total costs of this project, including an investment return to NSTAR and NU.

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

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. In 2006, the IRS disallowed the classification of the deduction as an ordinary loss. NSTAR appealed this decision and is currently in negotiation with the IRS Appeals office.

Prior to 2007, it was NSTAR’s tax accounting policy not to recognize tax benefits associated with an uncertain tax position until it was probable that such tax benefit would ultimately be realized. NSTAR determined that it was less than 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 earnings benefit of this uncertain tax position.

As of January 1, 2007, the potential tax loss was approximately $39.6 million. NSTAR adopted an accounting standard regarding uncertain tax positions effective January 1, 2007 which established a tax accounting recognition standard of more-likely-than-not, which is a lower threshold than NSTAR’s previous tax benefit recognition policy. Upon the adoption of the standard, NSTAR recognized the entire amount plus interest as an increase to its January 1, 2007 retained earnings balance.

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Construction-related Costs - Simplified Service Cost Method (SSCM)

In 2004, NSTAR amended its 2002 Federal income tax return to change its method of tax accounting for certain construction-related overhead costs previously capitalized to plant under a methodology prior to SSCM. Under SSCM, certain costs which were previously capitalized for tax purposes are deducted in the year incurred. NSTAR 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 was denied. NSTAR did not receive the requested refund amount due.

In August 2005, the IRS issued a Revenue Ruling and Treasury Regulations 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. This refund has been recorded as a current income tax receivable on the accompanying Consolidated Balance Sheets.

IRS Appeals and Examinations

As of December 31, 2009, the 2001 through 2007 Federal and state tax years remain open (including the SSCM and RCN Share Abandonment matters) and returns for those years are at the IRS Office of Appeals.

NSTAR is negotiating with IRS Appeals in an attempt to settle all issues relating to years 2001 through 2007. To date, we have reached agreement on the SSCM issue with a closing agreement expected to be signed in the first quarter of 2010. Upon approval of the settlement by the U.S. Congress Joint Committee on Taxation, NSTAR expects receipt of the $129 million of its refundable income tax receivable, plus interest, by mid-2010. Potential settlement discussions related to the RCN matter are continuing, however, the timing of any final settlement is uncertain as well as whether an agreement can be reached at an amount that would be acceptable to NSTAR. If an agreement is reached, it is reasonably possible that a charge could be recognized. Such agreement would also require Joint Committee approval. In the event that NSTAR is unsuccessful in reaching a reasonable settlement agreement with the IRS Appeals, it will continue the current plan to litigate the RCN tax matter. This action would delay resolution of this tax matter beyond 2010.

The 2008 Federal income tax return has been examined under the IRS Compliance Assurance Process (CAP) and NSTAR has received a “no change” letter. The 2009 Federal income tax return is being reviewed under CAP. This program accelerates the examination of the return in an attempt to resolve issues before the tax return is filed. The outcome of any potential audit adjustments and the timing are uncertain.

2010 Earnings Outlook

Earnings per share are expected to be in the $2.45 to $2.55 range. This range excludes the anticipated gain on the pending MATEP sale. Major assumptions supporting NSTAR’s earnings guidance for the year 2010 are as follows:

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Our expectations are based on our current assumptions described above, and are subject to risks and uncertainties (Refer to “ Cautionary Statement Regarding Forward-Looking Information ” preceding Item 1 “ Business ” and Item 1A, “ Risk Factors ” of this Form 10-K for more information).

Common Share Dividends

On November 19, 2009, NSTAR’s Board of Trustees declared a quarterly cash dividend of $0.40 per share for shareholders of record on January 8, 2010, payable February 1, 2010. NSTAR’s current annualized rate is $1.60 per share, a 6.7% increase over the previous rate of $1.50 per share. NSTAR expects that the growth rate of its common dividend will continue to be in-line with the growth rate of its 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 Continuing Operations

The following section of MD&A compares the results of continuing operations for each of the three fiscal years ended December 31, 2009, 2008, and 2007 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.

2009 compared to 2008

Executive Summary

NSTAR achieved earnings growth for 2009 during a very challenging year as a difficult economic climate and unfavorable weather conditions throughout the year negatively impacted its sales. NSTAR performance results in 2009 are as follows:

Earnings per common share were as follows:

Net income attributable to common shareholders was $253.2 million for 2009 compared to $237.5 million for 2008. Major factors on an after-tax basis that contributed to the $15.7 million, or 6.6%, increase include:

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These positive earnings factors were partially offset by:

Significant cash flow events during 2009 include the following:

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NSTAR’s electric sales in 2009 decreased primarily due to a cooler summer during 2009 as compared to 2008. 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 by the impact of customer and NSTAR-sponsored conservation measures. The 0.3% decrease in firm gas and transportation sales is due to greater use of conservation measures or restrictions on the use of natural gas for all customer segments, and commercial and industrial customers relocating their businesses to less costly regions or closing due to difficult economic conditions. The reduction in sales resulted despite colder weather in the first quarter and near-normal weather in the fourth quarter of 2009.

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 2009 was 4,507 MW measured on August 18, 2009 which was 9% 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. Weather impacts 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 many degrees 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 2009 and 2008 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. As shown on the table below, weather conditions during the first three quarters of 2009 measured by heating degree-days were higher/colder for 2009

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as compared to 2008, favorably impacting gas revenues. The fourth quarter of 2009 was warmer than the same quarter in 2008, unfavorably impacting gas revenues. Weather conditions during the three summer months ended September 30, 2009 measured by cooling degree-days were 11.4% lower/cooler for 2009 as compared to 2008, unfavorably impacting electric revenues. Refer to the “Electric Revenues” and “Gas Revenues” sections below for more detailed discussions.

Heating Degree-Days

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 distribution substations.

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The increase of $93.7 million, or 9.7%, in retail distribution and transmission revenues primarily reflects:

This increase was 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 $181.7 million decrease in energy, transition, and other revenues is primarily attributable to lower energy costs. Uncollected transition costs as a result of the reductions in transition rates are 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 $1.9 million increase in firm and transportation revenues is primarily attributable to colder weather conditions in the first quarter partially offset by customers reduced usage as a result of economic concerns. These factors resulted in the decrease in sales volumes of 0.3%.

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 decrease of $73.5 million primarily reflects a decrease in the cost of gas supply. These revenues are fully reconciled with the cost currently recognized by the Company and, as a result, do not have an effect on NSTAR’s consolidated net income.

Unregulated Operations Revenues

Unregulated operating revenues are derived from NSTAR’s telecommunications operations. Unregulated operating revenues were $16.3 million through December 31, 2009 compared to $15.0 million in 2008, an increase of $1.3 million, or 8.7%. The increase in unregulated revenues is primarily the result of new contracts added over the past year.

Operating Expenses

Purchased power and transmission costs were $1,260.5 million in 2009 compared to $1,353.7 million in 2008, a decrease of $93.2 million, or 6.9%. The decrease in expense reflects NSTAR Electric’s lower sales of 3.1%, as well as lower Basic Service and other energy costs of $140.6 million. These decreases are partially offset by higher transmission costs of $47.4 million primarily due to an increase in regional network support 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 consolidated net income.

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Cost of gas sold , representing NSTAR Gas’ supply expense, was $297.9 million in 2009 compared to $372.4 million in 2008, a decrease of $74.5 million, or 20%. The decrease in cost reflects the slight 0.3% decrease in sales, as well as lower storage and supply costs due to the fluctuations in energy markets, partially offset by the higher settlement of cash flow hedging contracts during the current year that increased expenses by $31.3 million. 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 expense have no impact on consolidated net income.

Operations and maintenance expense was $409.5 million in 2009 compared to $438.2 million in 2008, a decrease of $28.7 million, or 6.5%. The primary factors were lower liability claims cost ($6.1 million), lower labor and labor-related costs ($5.4 million), lower storm-related costs ($4.4 million), lower outside services and lower administrative and other operating costs ($11.9 million), and lower fuel costs due to declining prices ($2.1 million). In addition, there were lower pension and PBOP related PAM amortization costs ($5.8 million). Fluctuations in PAM amortization do not have an earnings impact as these costs are fully recovered through the pension adjustment mechanism. These factors are partially offset by higher bad debt expense of ($3.3 million).

Depreciation and amortization expense was $370.1 million in 2009 compared to $369.8 million in 2008, an increase of $0.3 million or less than 1%. The increase primarily reflects higher depreciable distribution and transmission plant in-service partially offset by completion of the 10-year amortization related to merger integration costs.

DSM and renewable energy programs expense was $89.0 million in 2009 compared to $73.3 million in 2008, an increase of $15.7 million, or 21.4%, which is consistent with the collection of conservation and renewable energy revenues. The increase reflects higher spending levels during 2009 required by the Green Communities Act (GCA). All costs are in accordance with program guidelines established by the DPU. DSM program costs are funded partially through proceeds from the Regional Greenhouse Gas Initiative and through NSTAR’s participation in the Forward Capacity Market. The remaining costs are collected from customers on a fully reconciling basis, plus a performance incentive.

Property and other taxes were $107.1 million in 2009 compared to $95.8 million in 2008, an increase of $11.3 million, or 11.8%, primarily reflecting higher overall property investments ($5.1 million) and higher municipal property tax rates ($6.3 million). NSTAR’s municipal property taxes are generally assessed based on net book value rather than assessed fair value.

Interest charges (income):

Long-term debt and transition property securitization certificate interest charges were $152.1 million in 2009 compared to $154.3 million in 2008, a decrease of $2.2 million, or 1.4%. The decrease in interest charges reflects:

This decrease was partially offset by:

Interest income and other, net were $24.4 million of net interest income in 2009 compared to $18 million of net interest income in 2008, an increase of $6.4 million, or 35.6%, due to increased interest income of $4.7 million related to higher regulatory deferrals and higher interest income on income tax matters of $2.2 million.

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Short-term debt interest charges were $1.4 million in 2009 compared to $10.3 million in 2008, a decrease of $8.9 million, or 86.4%, due to the reduction of 198 basis points in the 2009 weighted average borrowing rate. The weighted average short-term interest rates including fees were 0.41% and 2.39% in 2009 and 2008, respectively. The average level of borrowed funds in 2009 was nearly the same as in 2008.

Other income (deductions):

Other income was approximately $9.2 million in 2009 compared to $13.3 million in 2008, a decrease of $4.1 million. The decrease relates primarily to the absence of a favorable environmental settlement in 2008 ($4.8 million), the absence of company-owned life insurance proceeds received in 2008 ($1.3 million) and lower interest income in 2009 ($1.7 million). These amounts are partially offset by increases in the cash surrender value of insurance policies that occurred in 2009 ($4.3 million).

Other deductions were approximately $3.7 million in 2009 compared to $5.0 million in 2008, a decrease of $1.3 million. The decrease in other deductions primarily reflects the absence of a $1.5 million decrease in the cash surrender value of life insurance policies that occurred in 2008.

Income tax expense:

Income tax expense was $146.9 million in 2009 compared to $140.7 million in 2008, an increase of $6.2 million, or 4.4%, primarily reflecting the higher pre-tax operating income in 2009.

2008 compared to 2007

Executive Summary

NSTAR achieved several positive performance results in 2008:

Earnings per common share were as follows:

Net income attributable to common shareholders 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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