The accompanying MD&A focuses on factors that had a material effect on the financial condition, results of operations, and cash flows of NSTAR during the periods presented and should be read in conjunction with the accompanying consolidated financial statements and related notes and with the MD&A in NSTAR's 2008 Annual Report on Form 10-K.

Business Overview

NSTAR (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 core business is a traditional "pipes and wires" company with a continuing focus on shareholder value and a continued commitment for safe and reliable energy delivery to customers. NSTAR also focuses on providing accurate information and other helpful assistance to its customers, thereby providing a superior customer experience. NSTAR's strategy is to invest in transmission and distribution assets that will align with its core competencies.

Electric utility operations. For the nine months ended September 30, 2009, NSTAR derived 82% of its operating revenues from the transmission and distribution of electric energy through NSTAR Electric.

Gas operations. For the nine months ended September 30, 2009, NSTAR derived 14% of its operating revenues from the distribution of natural gas through NSTAR Gas.

Unregulated operations. For the nine months ended September 30, 2009, NSTAR derived 4% of its operating revenues from non-utility, unregulated operating subsidiaries involved in telecommunications and district energy operations.

Earnings. NSTAR's earnings are impacted by its customers' requirements for energy in the form of unit sales of electricity and natural gas, which directly determine the levels of electric retail distribution and transmission revenues and natural gas firm and transportation revenues recognized. In accordance with the regulatory rate structures in which NSTAR operates, its recovery of energy and energy-related costs are fully reconciled with the level of energy revenues currently recorded and, therefore, do not have an impact on earnings.

Net income attributable to common shareholders for the three and nine-month periods ended September 30, 2009 was $87.6 million and $205.6 million, or $0.82 and $1.92 diluted earnings per share, respectively, as compared to $85.8 million and $195.4 million, or $0.80 and $1.83 diluted earnings per share for the same periods in 2008, as further explained in this discussion.

Critical Accounting Policies and Estimates

For a complete discussion of critical accounting policies, refer to "Critical Accounting Policies and Estimates" in Item 7 of NSTAR's 2008 Form 10-K. There have been no substantive changes to those policies and estimates.

Rate Structure

a. Rate Settlement Agreement

NSTAR Electric is currently operating under a DPU-approved seven-year 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 rate adjustments 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.

b. Electric Rates

Retail electric delivery rates are established by the DPU and are comprised of:

·         a distribution charge, which includes a fixed customer charge
          and a demand and/or energy charge (to collect the costs of
          building and expanding the infrastructure to deliver power to
          its destination, as well as ongoing operating costs and certain
          DPU-approved safety and reliability program costs), a Pension
          and PBOP Rate Adjustment Mechanism (PAM) to recover related
          costs and a reconciling rate adjustment mechanism to recover
          costs associated with the residential assistance adjustment
          clause,
·         a basic service charge represents the collection of energy
          costs, including costs related to charge-offs of uncollected
          energy costs, through DPU-approved rate mechanisms.  Electric
          distribution companies in Massachusetts are required to obtain
          and resell power to retail customers through Basic Service for
          those 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,
·         a transition charge represents the collection of costs primarily
          from previously held investments in generating plants and costs
          related to existing above-market power contracts, and contract
          costs related to long-term power contracts buy-outs,

·         a transmission charge represents the collection of costs of
          moving the electricity over high voltage lines from generating
          plants to substations located within NSTAR's service area
          including costs allocated to NSTAR Electric by ISO-NE to
          maintain the wholesale electric market,
·         an energy conservation charge represents a
          legislatively-mandated charge to collect costs for demand-side
          management programs and energy efficiency programs, and
·         a renewable energy charge represents a legislatively-mandated
          charge to collect the costs to support the development and
          promotion of renewable energy projects.

c. 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 have no impact on NSTAR Gas' operating income because a substantial portion of the margin for such service is returned to its firm customers as rate reductions.

Retail gas delivery and supply rates are established by the DPU and are comprised of:

·         a distribution charge consists of a fixed customer charge and a
          demand and/or energy charge that collects the costs of building
          and expanding the gas infrastructure to deliver gas supply to
          its customers' destination.  This also includes collection of
          ongoing operating costs,
·         a seasonal cost of gas adjustment clause (CGAC) represents the
          collection of gas supply costs, pipeline and storage capacity,
          costs related to charge-offs of uncollected energy costs and
          working capital related costs.  The CGAC is reset every six
          months.  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%,
·         a local distribution adjustment clause (LDAC) primarily
          represents the collection of demand-side management costs,
          environmental costs, PAM related costs, and costs associated
          with the residential assistance adjustment clause.  The LDAC is
          reset annually and provides for the recovery of certain costs
          applicable to both sales and transportation customers.

NSTAR Gas purchases financial contracts based on 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. All costs incurred or benefits realized when these contracts are settled are included in the CGAC of NSTAR Gas.

d. Regulatory Matters

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 borne by regional customers. If NSTAR Electric's efforts to reduce customers' costs are successful, it is allowed to retain a portion of those savings as an incentive, as well as recover related litigation costs. Under the terms of the Rate Settlement Agreement, NSTAR Electric was to share in 25% of the savings applicable to its customers. The recovery of NSTAR Electric's share of benefits is to be collected over three years. As a result of its role in two RMR cases, NSTAR Electric had sought to collect $9.8 million annually for three years and began collecting some of these incentive revenues from its

customers effective January 1, 2007, subject to final DPU approval. Through September 30, 2009, approximately $17.3 million has been collected from customers for the Wholesale Power Cost Saving Initiatives. NSTAR is unable to predict the timing or ultimate outcome of this DPU proceeding. In the event an adverse decision is issued, it would not have a material impact on the Company's results of operations.

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 $11.1 million and $13.1 million in 2006 and 2007, respectively. This includes incremental operations and maintenance and revenue requirements on capital investments. The final reconciliation of 2006 and 2007 CPSL costs recovery is currently under review by the DPU. The incremental costs for the year 2008 are currently under review by the Company and are estimated to be approximately $15 million. NSTAR anticipates filing its final 2008 CPSL cost recovery reconciliation with the DPU in the fourth quarter of 2009. 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.

Basic Service Bad Debt Adder

On July 1, 2005, in response to a generic DPU order that required electric utilities in Massachusetts to reflect 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 and effectively eliminates 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 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 September 30, 2009, the potential impact to earnings of a disallowance of the bad debt adder would be approximately $18.9 million, pre-tax. NSTAR cannot predict the timing of this proceeding.

FERC Transmission ROE

NSTAR earns an 11.14% ROE on local transmission facility investments. The ROE on NSTAR's regional transmission facilities is 11.64%. Additional incentive adders are determined on a case-by-case basis according to FERC's national transmission incentive rules. The FERC may grant a variety of financial incentives, including ROE basis point incentive adders for qualified investments made in new regional

transmission facilities that can bring the ROE for NSTAR up to 12.64% for certain qualified regional investments. In addition, NSTAR may qualify for other incentives on future transmission projects based upon certain conditions that could bring the ROE to 13.1%.

Other

a. Energy Efficiency Plans - NSTAR Electric and NSTAR Gas

NSTAR Electric and NSTAR Gas 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 is to be effective January 1, 2010, and 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 as yet have rate decoupling mechanisms in place to implement lost base revenue rate adjustment mechanisms that will offset reduced distribution rate revenues as a result of successful energy efficiency programs.

During 2009, NSTAR Electric anticipates spending approximately $74.2 million.
For 2010, NSTAR Electric anticipates that the program will constitute $130 million in spending, subject to DPU approval.

During 2009, NSTAR Gas anticipates spending approximately $6.1 million. For 2010, NSTAR Gas anticipates that the program will constitute $15.7 million in spending, subject to DPU approval.

b. American Recovery and Reinvestment Act of 2009 (ARRA)

The American Recovery and Reinvestment Act of 2009 (ARRA) provides resources for significant increases in 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 governmental 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.

NSTAR Electric is in the process of pursuing U.S. Department of Energy (DOE) Funding Opportunities made available under the ARRA. In August 2009, NSTAR applied for Federal grants for its Smart Grid Programs. The requested funding represents 50% of the estimated total project costs. On October 27, 2009, NSTAR Electric received notice from the DOE that it had been awarded a $10 million grant related to a distribution automation proposal. 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.

c. Potential Transmission Investment

On May 21, 2009, NSTAR and Northeast Utilities announced that the FERC issued a declaratory judgment that ruled favorably on the proposed structure of a transmission arrangement for a new participant-funded transmission line between New England and Quebec. Under this arrangement, firm transmission rights would be assigned to Hydro-Quebec, and the proposed line would transmit at least 1,200 megawatts of power. NSTAR, Northeast Utilities and Hydro-Quebec have agreed to develop this project, and are currently negotiating long-term transmission service and purchase power agreements.

Results of Operations

The following section of MD&A compares the results of operations for each of the three and nine-month periods ended September 30, 2009 and 2008 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.

Earnings Outlook

NSTAR is maintaining its earnings guidance of between $2.33 and $2.43 per share for 2009.

Common Share Dividends

NSTAR's current quarterly cash dividend rate is $0.375 per share or $1.50 per share on an annualized basis. On September 24, 2009, NSTAR's Board of Trustees declared a quarterly cash dividend of $0.375 per share to shareholders of record on October 9, 2009, payable November 2, 2009.

Three Months Ended September 30, 2009 compared to Three Months Ended September 30, 2008

Executive Summary of Quarterly Results

Earnings per common share were as follows:

Three Months Ended September 30, 2009 2008 % Change Basic and Diluted $ 0.82 $ 0.80 2.5

Net income attributable to common shareholders was $87.6 million for the quarter ended September 30, 2009 compared to $85.8 million for the same period in 2008.
Major factors (after-tax) that contributed to the $1.8 million, or 2.1%, increase in the three months ended September 30, 2009 include:

· Lower operations and maintenance expense primarily due to milder weather in 2009 that led to fewer emergent restoration events, lower storm-related costs due to the absence of severe storms. Also contributing were control of outside services and lower administrative and other operating costs ($2.9 million)
· Higher transmission margin primarily due to higher current earnings resulting from higher investment base ($1.3 million)
· Higher other income due to changes in cash surrender value of executive life insurance policies ($1.4 million)

These increases in earnings factors were partially offset by:

· Lower earnings from NSTAR's unregulated businesses ($1.2 million)
· Higher depreciation and amortization and property tax expenses in 2009 related to higher regulated electric and gas plant investments and higher municipal tax rates ($3.1 million)

Significant cash flow events during the quarter include the following:

· Cash flows from operating activities provided approximately $227.9 million, an increase of $69.4 million as compared to the same period in 2008. The increase primarily reflects a decrease in relative accounts receivable balances driven by lower energy supply costs and a decrease in relative gas fuel inventory balances driven by a transition to a portfolio manager arrangement
· NSTAR invested approximately $76 million in capital projects to improve system reliability and capacity
· NSTAR paid approximately $40.1 million in common share dividends and retired approximately $42 million in long-term and securitized debt

Energy sales

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

Retail Electric Sales - MWh             Three Months Ended September 30,
                                            2009          2008    % Change

 Residential                           1,760,094     1,795,946     (2.0)
 Commercial, Industrial, and other     3,978,336     4,148,861     (4.1)
  Total retail sales                   5,738,430     5,944,807     (3.5)



Firm Gas Sales and Transportation - BBtu     Three Months Ended September 30,
                                              2009         2008       % Change

 Residential                                 1,409        1,368         3.0
 Commercial and Industrial                   2,710        2,871        (5.6)
 Municipal                                     217          162         34.0
  Total firm sales                           4,336        4,401        (1.5)

NSTAR's electric energy sales in the three months ended September 30, 2009 declined 3.5% compared to 2008 primarily due to unfavorable weather conditions resulting from a cooler summer during 2009 as compared to 2008. Cooling degree-days in the Boston area for the three months ended September 30, 2009 were down 11.4%, from the same period in 2008. Electric sales were also impacted by economic conditions and customer conservation behavior.

The 1.5% decrease in firm gas and transportation sales is due to economic conditions and continued customer conservation efforts.

Weather, fluctuations in fuel costs, conservation measures, and economic conditions affect sales to NSTAR's residential and small commercial customers.
Economic conditions, fluctuations in 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 variations. Refer to the "Electric Revenues" and "Gas Revenues" sections below for more detailed discussions.

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, economic conditions, energy conservation, and other factors. Refer to the "Cautionary Statement Regarding Forward-Looking Information" section preceding Part 1 "Financial Information" of this Form 10-Q.

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

Degree-days measure changes in daily mean temperature levels. A degree-day is a unit measuring how much the outdoor daily mean temperature falls below (in the case of heating) or rises above (in the case of cooling) a base of 65 degrees.
The comparative information below relates to heating degree-days for the three months ended September 30, 2009 and 2008 and the number of heating degree-days in a "normal" year using 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 Regional Airport and Boston's Logan Airport for heating degree-day data and cooling degree-day data, respectively. Weather conditions during the three months ended September 30, 2009 measured by heating and cooling degree-days, respectively, were 102.2% higher/colder related to heating degree-days and 11.4% lower/cooler related to cooling degree-days for 2009 as compared to 2008. Refer to the "Electric Revenues" and "Gas Revenues" sections below for more detailed discussions.

          Heating Degree-Days
          Three months ended September 30, 2009                     271
          Three months ended September 30, 2008                     134
          Normal 30-Year Average                                    177

          Percentage that 2009 was colder than 2008              102.2%
          Percentage that 2009 was colder than 30-year average    53.1%



           Cooling Degree-Days
           Three months ended September 30, 2009                    512
           Three months ended September 30, 2008                    578
           Normal 30-Year Average                                   593

           Percentage that 2009 was cooler than 2008              11.4%
           Percentage that 2009 was cooler than 30-year average   13.7%

Operating revenues

Operating revenues for the third quarter of 2009 decreased $120.7 million, or 13.5%, from the same period in 2008 as follows:

(in millions)                            Three Months Ended September 30,        Increase/(Decrease)
                                                  2009             2008           Amount        Percent
Electric revenues
 Retail distribution and transmission     $      331.7     $      303.7      $      28.0            9.2 %
 Energy, transition and other                    367.4            489.3           (121.9 )        (24.9 %)
  Total retail electric revenues                 699.1            793.0            (93.9 )        (11.8 %)
Gas revenues
 Firm and transportation                          15.6             15.7             (0.1 )         (0.6 %)
 Energy supply and other                          26.8             45.2            (18.4 )        (40.7 %)
  Total gas revenues                              42.4             60.9            (18.5 )        (30.4 %)

Unregulated operations revenues                   30.0             38.3             (8.3 )        (21.7 %)
  Total operating revenues                $      771.5     $      892.2      $    (120.7 )        (13.5 %)

Electric revenues

NSTAR's largest earnings sources are the revenues derived from distribution and transmission rates approved by the DPU and the 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.

The increase of $28 million, or 9.2%, in retail distribution and transmission revenues primarily reflects:

· Increased transmission revenues primarily due to the recovery of a higher transmission investment base and recovery of higher regional network service costs ($28 million)
· Increased electric revenues resulting from the annual inflation rate adjustment ($3.7 million)

These increases were partially offset by:

· Decreased energy sales of 3.5% due to the impact of weather conditions, economic conditions and customer conservation measures ($3.7 million)

Energy, transition, and other revenues primarily represent charges to customers . . .