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. Prior to January 1, 2007, NSTAR’s retail electric utility subsidiaries were Boston Edison, ComElectric and Cambridge Electric. Its wholesale electric subsidiary was Canal. NSTAR’s three retail electric companies collectively have operated under the trade name “NSTAR Electric.” NSTAR’s retail natural gas distribution utility subsidiary is NSTAR Gas. NSTAR’s nonutility, unregulated operations include district energy operations primarily through its AES subsidiary, telecommunications operations (NSTAR Com) and a liquefied natural gas 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 2007, 2006 and 2005.

NSTAR’s Rate Settlement Agreement anticipated the transfer of the net assets, structured as a merger of NSTAR’s electric subsidiary companies Cambridge Electric, ComElectric and Canal, to Boston Edison. NSTAR requested and received final approval of this merger from the DPU and FERC during the fourth quarter of 2006. As part of this merger, on December 1, 2006, NSTAR filed blended basic service rates with the DPU, effective January 1, 2007. The individual Boston Edison, ComElectric and Cambridge Electric basic service rates were blended into rates applicable to the entire NSTAR Electric service territory pursuant to the DPU’s approval of the NSTAR Electric merger. The merger was effective as of January 1, 2007 and Boston Edison was renamed NSTAR Electric Company.

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 $725 million, $265.5 million and $409 million, respectively, in notes to a special purpose trust created by two Massachusetts state agencies. NSTAR has no variable interest entities.

NSTAR derives its revenues primarily from the sale of energy, distribution and transmission services to customers and from its unregulated businesses. NSTAR’s earnings are impacted by fluctuations in unit sales of electric kWh and natural gas MMbtu, which directly determine the level of distribution and transmission

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revenues recognized. In accordance with the regulatory rate structure in which NSTAR operates, its recovery of energy costs are fully reconciled with the level of energy revenues currently recorded and, therefore, do not have an impact on earnings. As a result of this rate structure, any variability in the cost of energy supply purchased will impact purchased power and cost of gas sold expense and corresponding revenues but will not affect the Company’s earnings.

Critical Accounting Policies and Estimates

NSTAR’s discussion and analysis of its financial condition, results of operations and cash flows are based upon the accompanying Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Consolidated Financial Statements required management to make estimates and judgments that affect the reported amount of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements. Actual results may differ from these estimates under different assumptions or conditions.

Critical accounting policies and estimates are defined as those that require significant judgment and uncertainties, and potentially may result in materially different outcomes under different assumptions and conditions. NSTAR believes that its accounting policies and estimates that are most critical to the reported results of operations, cash flows and financial position are described below.

a. Revenue Recognition

Utility revenues are based on authorized rates approved by the DPU and FERC. Revenues related to the sale, transmission and distribution of delivery service are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on systematic meter readings throughout the month. Meters that are not read during a given month are estimated and trued-up in a future period. At the end of each month, amounts of energy delivered to customers since the date of the last billing date are estimated and the corresponding unbilled revenue is recorded. Unbilled electric revenue is estimated each month based on daily generation volumes (territory load), estimated line losses and applicable customer rates. Unbilled natural gas revenues are estimated based on estimated purchased gas volumes, estimated gas losses and tariffed rates in effect. Accrued unbilled revenues totaled $60 million and $59 million in the accompanying Consolidated Balance Sheets as of December 31, 2007 and 2006, 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 unbilled revenue during the seasonal periods mentioned above.

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 based on the probability of current and future cash inflows. Regulatory assets represent incurred or accrued costs that have been deferred because they are probable of future recovery from customers. As of December 31, 2007 and 2006, NSTAR has recorded regulatory assets of $2.6 billion and $2.9 billion, respectively. NSTAR continuously reviews these assets to assess their ultimate

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recoverability within the approved regulatory guidelines. NSTAR expects to fully recover these regulatory assets in its rates. If future recovery of costs ceases to be probable, NSTAR would be required to charge these assets to current earnings. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.

c. Pension and Other Postretirement Benefits

NSTAR’s annual pension and other postretirement benefits costs are dependent upon several factors and assumptions, such as 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.

There were no significant changes to NSTAR’s pension benefits in 2007, 2006 and 2005 that had a material impact on recorded pension costs. As further described in Note G , “Pension and Other Postretirement Benefits,” to the accompanying Consolidated Financial Statements, NSTAR’s discount rates at December 31, 2007 and 2006 were 6.25% and 6%, respectively, and align with market conditions and the characteristics of NSTAR’s pension obligation. The expected long-term rate of return on its pension plan assets for 2007 remained at 8.4% (net of plan expenses), the same as 2006. These assumptions will have an impact on reported pension costs in future years in accordance with the cost recognition approach of SFAS 87. This impact, however, is mitigated through NSTAR’s regulatory rate treatment of qualified pension and PBOP costs. (Refer to a further discussion of regulatory accounting treatment below.) In determining pension obligation and cost amounts, these assumptions may change from period to period, and such changes could result in material changes to recorded pension and PBOP costs and funding requirements.

NSTAR’s Pension Plan (the Plan) assets, which partially consist of equity investments, are affected by fluctuations in the financial markets. These fluctuations in market returns will have an impact on pension costs in future periods. In addition, fluctuation in the market value of these assets will have an impact on the recorded funded status of these benefit plans, in accordance with the requirements of SFAS 158.

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

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 20-year time period. In 2007, NSTAR kept the expected long-term rate of return on plan assets at 8.4% as a result of the prevailing outlook for investment returns. This rate is presented net of both administrative and investment expenses, which have averaged approximately 0.6% for 2007, 2006 and 2005.

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.

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

On August 17, 2006, the Pension Protection Act of 2006 (the Act) was enacted into law. The Act requires employers with defined-benefit pension plans to make contributions to meet a certain funding target and eliminate funding shortfalls. The Company is in compliance with this Act. Based on its current funding level and the provisions of the Act, NSTAR does not anticipate making contributions to the Plan in 2008.

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

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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 collectively has an equity ownership of 14% in CY, 14% in YA, and 4% in MY, (collectively, the “Yankee Companies”).

CY was notified on November 26, 2007 by the NRC that its former generating plant site was decommissioned in accordance with NRC procedures. Also, 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.

On December 21, 2006, the shareholders of CY approved a resolution to repurchase 276,575 of its outstanding shares from all equity holders at a price of $108.4681 per share and declared those shares payable at the close of business on that date. The total value of this buy-back transaction was $30 million. NSTAR Electric’s reduction of its equity ownership resulting from the CY buy-back of 38,721 shares was approximately $4.2 million.

Yankee Companies Spent Fuel Litigation

On October 4, 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 relating 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. NSTAR cannot predict the ultimate outcome of this decision on appeal or the subsequent complaints.

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 to apply, the normal purchases and sales exception. As a result, these agreements are not reflected as either an asset or liability on the accompanying Consolidated Balance Sheets. The majority of NSTAR’s gas supply contracts do not qualify for the normal purchases and sales exception; however, these contracts contain market based pricing mechanisms, and therefore, no adjustments are required.

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Hedging Agreements

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. The objective of this practice is to minimize fluctuations in prices to NSTAR firm gas sales customers. These financial contracts do not procure gas supply and therefore NSTAR Gas does not take physical delivery of gas. These contracts qualify as derivative financial instruments, specifically cash flow hedges. 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 currently. All actual costs and benefits incurred are included in the firm sales CGAC and are fully recoverable from customers. As a result, NSTAR Gas records an offsetting regulatory asset or liability for the market price changes, in lieu of recording the adjustment to Other Comprehensive Income. Currently, these derivative contracts extend through April 2009. At December 31, 2007 and 2006, NSTAR has recorded a liability and a corresponding regulatory asset of $10.5 million and $32.7 million, respectively, reflecting the fair value of these contracts. During 2007, approximately $30.4 million of these financial contracts were settled resulting in payments by NSTAR to the counterparties to the contracts.

Asset Retirement Obligations

The 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 its regulated utility businesses has no impact on NSTAR’s 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 asbestos 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, 2007 and 2006, the estimated amount of the cost of removal included in regulatory liabilities was approximately $259 million and $260 million, respectively, based on the estimated cost of removal component in current depreciation rates. At December 31, 2007, NSTAR has an asset retirement cost in utility plant of $3 million, an asset retirement liability of $23 million and a regulatory asset of $18 million.

New Accounting Standards

SFAS No. 157

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS 157), which provides enhanced guidance for using fair value measurements in financial reporting. While the standard does not expand the use of fair value in any new circumstance, it has applicability to several current accounting standards that require or permit entities to measure assets and liabilities at fair value. SFAS 157 defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. NSTAR adopted this standard on January 1, 2008 with no impact to its results of operations, financial position or cash flows.

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SFAS No. 159

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159) . This statement provides companies with an option to report selected financial assets and liabilities at fair value. NSTAR adopted this standard on January 1, 2008. NSTAR did not elect the fair value option, and therefore, SFAS 159 had no impact on its results of operations, financial position or cash flows.

Rate and Regulatory Proceedings

a. 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 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 reliability and performance; the reports indicate that no penalty was assessable for 2006. This is subject to final DPU approval. NSTAR has estimated that no penalty was assessable for 2007.

The Rate Settlement Agreement approved by the DPU on December 30, 2005 established additional performance measures applicable to NSTAR’s rate regulated subsidiaries. The Rate Settlement Agreement establishes, for NSTAR Electric, a performance benchmark relating to its poor performing circuits, with a maximum penalty or incentive of up to $0.5 million. For 2006 and 2007, NSTAR Electric determined that its performance related to these applicable circuits exceeded the established benchmarks and therefore, accrued its incentive entitlement of $0.5 million for each of those years, subject to final DPU approval.

b. Rate Structures

Retail Electric 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 power. As of December 31, 2007, 2006 and 2005, customers of NSTAR Electric had approximately 47%, 49%, and 68%, respectively, of their load requirements provided through basic service. For 2007 and 2006, the residential, commercial and industrial customer classes’ load requirements provided through basic service were 56%, 31% and 13%, respectively, and 52%, 31% and 17%, respectively. NSTAR Electric fully recovers its energy costs, including costs related to charge-offs of uncollected energy costs, through DPU-approved rate mechanisms. Though energy delivery charges vary slightly by region, the basic service price for all residential customers decreased an average of 8% from $0.1186 to $0.1084 per kilowatt-hour effective July 1, 2007. Medium and large commercial customers decreased an average of 17% from $0.1142 cents to $0.0947 cents per kilowatt-hour effective October 1, 2007. The basic service price for all residential customers increased an average of 3%, from $0.1084 to $0.1117 per kilowatt-hour effective January 1, 2008. Medium and large commercial customers increased an average of 17% from $0.0949 cents to $0.1106 cents per kilowatt-hour effective January 1, 2008.

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Changes in Massachusetts’ Regulatory Environment

In January 2007, a new Governor and Attorney General took office. The Governor has a very significant influence on energy regulatory policy in Massachusetts. The Governor has identified energy policy as a key initiative of his administration, and has functionally reorganized key energy offices. His reorganization plan, which took effect on April 11, 2007, created a new cabinet position—the Secretary of Energy and Environmental Affairs. The Secretary now oversees a newly formed CUC, consisting of three commissioners. The CUC leads the DPU, a newly formed agency that has jurisdiction over electric, natural gas, water and transportation matters. The agency previously responsible for such functions, the MDTE, was eliminated.

During late 2007 and January 2008, the Massachusetts House of Representatives and Senate drafted and approved two separate energy policy reform bills. These bills address energy procurement, renewable and alternative energy generation and other green power initiatives and utility regulation. Both bills are currently under review by a joint House and Senate Conference Committee. This Committee is expected to combine the two bills into one comprehensive energy policy reform bill for ultimate approval. It is anticipated that the resulting bill will be enacted into law during 2008. NSTAR cannot anticipate or predict what terms the final bill will include, and therefore, cannot predict the timing, ultimate approval, or potential impact of this legislation.

Proposed Rate Decoupling

On June 22, 2007, the DPU opened a generic investigation into rate structures and revenue recovery mechanisms in order to promote efficient deployment of demand resources in Massachusetts. Demand resources are installed equipment, measures or programs that reduce end-use demand for electricity or natural gas. This investigation will include, in part, a review of whether and how existing rate mechanisms may be changed to better align a company’s financial interests with the needs to provide greater energy efficiencies and foster the advancement of price-responsive demand in regional wholesale energy markets. Historically, Massachusetts retail electric and natural gas distribution companies have sponsored customer-funded energy efficiency and load reduction programs with an incentive to mitigate a company’s lost retail distribution revenues. However, there is an inherent disconnect between the sponsorship of such programs and the continued maintenance of revenue and sales growth levels. The DPU has opened a proceeding to determine whether it should implement a base revenue adjustment mechanism that “decouples” a utility’s retail distribution revenues (the recovery of fixed infrastructure costs, including a return component and the recovery of other operating costs) and its sales volumes.

NSTAR supports the DPU’s objectives that would promote greater levels of energy efficiencies and alternative energy resources. It is important that the outcome of this generic decoupling proceeding effectively achieve these objectives in balance with other rate policy objectives. NSTAR Electric anticipates working to achieve an effective rate mechanism with the DPU. However, NSTAR cannot predict the timing or the ultimate outcome of this proceeding.

Rate Settlement Agreement and Other Regulatory Matters

On December 30, 2005, the DPU approved a seven-year Rate Settlement Agreement (“Rate Settlement Agreement”) between NSTAR, the AG, and several interveners. For 2006, the Rate Settlement Agreement required NSTAR Electric to lower its transition rates by $20 million, effective January 1, 2006, and by an additional $30 million, effective May 1, 2006, from what would otherwise have been billed in 2006. Effective May 1, 2006, NSTAR Electric increased its distribution rates by $30 million. Uncollected transition charges as a result of the reductions in transition rates are deferred and collected through future rates with a carrying charge at a rate of 10.88%. Beginning January 1, 2007 and continuing through 2012, the Rate Settlement Agreement establishes annual inflation-adjusted distribution rate increases that are offset by an equal and corresponding reduction in transition rates.

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Wholesale Power Cost Savings Initiatives

The Rate Settlement Agreement provides for 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, the Company is allowed to retain a portion of those savings, as well as related litigation costs, as an incentive. Under the terms of the Rate Settlement Agreement, NSTAR Electric is 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, and the aggregate annual recovery is capped at 2% of the annual distribution and transmission service revenues. As a result of NSTAR’s role in two RMR cases, NSTAR Electric had sought to collect $9.8 million annually for three years and began recognizing and collecting 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 allows NSTAR Electric to collect $6.3 million of the savings annually for three years effective January 1, 2007. In addition, it stipulates that NSTAR Electric will share 12.5% of the savings applicable to its customers in its future efforts related to new wholesale energy cost savings cases. Approval of this Settlement Agreement and of the incentives is required by the DPU. The DPU has extended the deadline to issue a decision on this Agreement until February 29, 2008.

NSTAR is unable to predict the ultimate outcome of this proceeding. In the event an adverse decision is reached it should not have a material impact on the Company’s reported results of operations for 2007. However, such a decision could have an impact on future results of operations and cash flows.

Regulatory Proceedings—DPU

NSTAR Electric made its 2006 Distribution Rate Adjustment/Reconciliation Filing on September 29, 2006. The filing implements the provisions of the Rate Settlement Agreement that supports the establishment of new distribution and transition rates that became effective January 1, 2007. Also effective on this date, NSTAR Electric’s distribution rates include elements of a SIP and a CPSL program that require an offsetting adjustment to its transition rate. The performance-based SIP is based on the gross domestic product price index minus a productivity offset and rate adjustment factor that resulted in a 2.64% increase in distribution rates. The CPSL program relates to incremental spending for double pole removal, pole replacements and underground electric safety programs, which include stray-voltage remediation and manhole inspections, repairs and upgrades. For 2006, the CPSL cost recovery was estimated to be $13.3 million and that amount was included in retail distribution rates for 2007. The final reconciliation of 2006 CPSL costs and revenues is currently under review by the DPU. On October 1, 2007, NSTAR Electric filed for the establishment of new distribution (SIP of 2.68%), transition and transmission rates that became effective on January 1, 2008. This filing included recovery of estimated CPSL costs of $24 million to be collected during 2008. This balance includes the under-collection of 2006 CPSL amounts. Recovery of transition and CPSL costs is subject to DPU review and reconciliation to actual costs. NSTAR cannot predict the timing or the ultimate outcome of these pending filings.

Basic Service Bad Debt Adder

On July 1, 2005, in response to a generic DPU order that required electric utilities 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 approved by the DPU on December 30, 2005. 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.

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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. However, on June 28, 2007, the DPU issued an order approving the implementation of a revised basic service rate but required NSTAR Electric to reduce distribution rates by the increase in its basic service bad debt charge-offs. Such action would effectively 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 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, 2007, the potential impact to earnings of eliminating the bad debt adder was approximately $14 million, pre-tax. NSTAR cannot predict the timing or the ultimate outcome of this proceeding.

In addition, the Rate Settlement Agreement provided for a preliminary agreement to certain terms of a merger and asset transfer of NSTAR’s electric subsidiaries that became effective on January 1, 2007, and implemented a 50% / 50% earnings sharing mechanism based on NSTAR Electric’s aggregate return on equity should it exceed 12.5% or fall below 8.5%. Should the return on equity fall below 7.5%, NSTAR Electric may file a request for a general rate increase.

In December 2005, NSTAR Electric filed proposed transition rate adjustments for 2006, including a preliminary reconciliation of transition, transmission, basic service and default service costs and revenues through 2005. The DPU subsequently approved tariffs for each retail electric subsidiary effective January 1, 2006. Updated reconciliations to reflect final 2005 costs and revenues were filed during the second quarter of 2006 for Boston Edison, ComElectric and Cambridge Electric. A settlement agreement between the AG and NSTAR Electric on the reconciliation of the Boston Edison costs and revenue for 2004 and 2005 was filed with the DPU on May 29, 2007, and approved by the DPU on July 23, 2007. Evidentiary hearings were conducted on the reconciliation of the ComElectric and Cambridge Electric costs and revenue for 2005. The case is pending a decision at the DPU and NSTAR cannot predict the timing or the ultimate outcome of this filing.

c. Wholesale Market and Transmission Changes

Regulatory Proceedings—FERC

On July 9, 2007, FERC issued an Order that 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 reached an agreement in principle with the FERC staff and the AG. A final settlement is expected to be executed during the first quarter of 2008. This settlement will be subject to FERC approval. The implementation of this settlement is not expected to have a material impact on the Company’s results of operations, financial position or cash flows.

NSTAR’s former subsidiaries Cambridge Electric and ComElectric filed proposed changes to their OATT with the FERC on March 30, 2005 to provide for consistent application of the OATT among all NSTAR Electric companies. These tariffs became effective on June 1, 2005 and expired on December 31, 2006; however, the FERC set certain rate-related issues raised in the proceeding for hearing, but held the hearing in abeyance pending settlement discussions with the AG, the sole intervener. On November 17, 2006, a settlement agreement that resolved all issues in the proceeding was filed at FERC. The settlement was approved by the full Commission on March 1, 2007.

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FERC Transmission ROE

On October 31, 2006, the FERC authorized, for the participating New England Transmission Owners, including NSTAR Electric, an ROE on regional transmission facilities of 10.2% plus a 50 basis point adder for joining a RTO from February 1, 2005 (the RTO effective date) through October 31, 2006, and an ROE of 11.4% thereafter. In addition, FERC granted a 100 basis point incentive adder to ROE for qualified investments made in new regional transmission facilities, that when combined with FERC’s approved ROEs, provide 11.7% and 12.4% returns for the respective time frames. RTO-NE ratepayers will benefit as a result of this order because it responds to the need to enhance the New England transmission grid to alleviate congestion costs and reliability issues. Transmission projects that are completed and in progress including NSTAR Electric’s 345kV project, have significantly minimized these congestion costs and enhance reliability in the region. The New England Transmission Owners accepted all but one of the terms of the October 31, 2006 FERC decision, and on November 30, 2006, filed for a request for rehearing involving the calculation of the base ROE, for which the FERC did not provide an explanation for its action and which the New England Transmission Owners believe is not supported by the record evidence. The New England Transmission Owners contend that the base ROE should be 10.5%. The Company is unable to determine the ultimate timing or result of the rehearing process or of the ultimate FERC decision.

d. Gas Rates

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

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%.

Effective May 1, 2007, the DPU approved a summer period CGAC factor of $0.8726/therm, a 27% decline in cost from the previous rate level. The DPU approved the CGAC factor effective November 1, 2007 for the 2007-2008 winter heating season of $0.9799/therm that was 18% lower than the rate set in November 2006 of $1.1949/therm. These rates reflect normal differences between winter and summer prices and the continued volatility of fuel prices on the NYMEX. The 2005-2006 winter season DPU-approved CGAC factor was revised downward to $0.90/therm effective March 1, 2006 from a factor of $1.3955/therm effective January 1, 2006 to reflect decreases in the cost of gas caused by varying market conditions. Effective May 1, 2006, the DPU approved a summer period CGAC factor of $1.1855/therm that included higher forecasted gas commodity costs. Changes in the cost of gas supply have no impact on the Company’s earnings due to this rate recovery mechanism.

On February 28, 2005, the DPU-approved a petition by NSTAR Gas to change a portion of its gas procurement practices. As approved, NSTAR Gas began purchasing financial contracts based upon NYMEX natural gas futures in order to reduce cash flow variability associated with the purchase price for approximately one-third of its natural gas purchases. Refer to the accompanying “Hedging Agreements” section disclosed above for a further discussion.

Nonmonetary Transactions—2006

In the third and fourth quarters of 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

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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 the 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.

Sale of Properties

There were no material property sales recognized during 2007.

On November 8, 2006, NSTAR Electric completed the sale of a former office complex in Wareham, Massachusetts for $7.7 million. The regulatory treatment of the proceeds remains subject to DPU approval. As a result, this transaction had no impact on 2006 earnings.

On April 26, 2006 and September 19, 2006, NSTAR Electric sold two parcels of nonutility land in Boston, Massachusetts and Lincoln, Massachusetts for $6.2 million, realizing a pre-tax gain on the sale of $4.1 million. This gain is reflected as a component of other income, net on the accompanying Consolidated Statements of Income.

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

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

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

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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. As a result, 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 of December 31, 2007 and 2006, this refund has been recorded as a non-current refundable income tax on the accompanying Consolidated Balance Sheets.

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 contingency 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.

Earnings Outlook

NSTAR is currently projecting to achieve earnings per share for the year ended December 31, 2008 in the $2.16 - $2.26 range. This guidance reflects the following factors: electric sales are expected to increase 1% to 2%, assuming normal weather conditions; operations and maintenance expense is expected to grow 1% to 2%; and capital expenditures for the year are expected to be approximately $440 million, including approximately $140 million for transmission projects.

Common Share Dividends

On November 15, 2007, NSTAR’s Board of Trustees declared a quarterly cash dividend of $0.35 per share for shareholders of record on January 10, 2008, payable February 1, 2008. NSTAR’s current annualized rate is $1.40 per share, a 7.7% increase over the previous rate of $1.30 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 upon the Company’s financial position and other relevant considerations at the time.

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