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NORTHEAST UTILITIES

THE CONNECTICUT LIGHT AND POWER COMPANY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

WESTERN MASSACHUSETTS ELECTRIC COMPANY

SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES

LITIGATION REFORM ACT OF 1995

References in this Annual Report on Form 10-K to "NU," "we," "our," and "us" refer to Northeast Utilities and its consolidated subsidiaries.

From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, financial performance or growth and other statements that are not historical facts.  These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995.  You can generally identify our "forward-looking statements"forward-looking statements through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions.  Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance.  These expectations, estimates, assumptions or projections mayma y vary materially from actual results.  Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to, to:

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actions or inaction by local, state and federal regulatory bodies

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changes in business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products and services

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changes in weather patterns

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changes in laws, regulations or regulatory policy

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changes in levels and timing of capital expenditures

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disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly

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developments in legal or public policy doctrines

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technological developments

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changes in accounting standards and financial reporting regulations

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fluctuations in the value of our remaining competitive electricity p ositions, contracts

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actions of rating agencies

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The expected timing and likelihood of completion of the proposed merger with NSTAR, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management's time and attention from our ongoing business during this time period, as well as the ability to successfully integrate the businesses, and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect and

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other presently unknown or unforeseen factors.  

Other risk factors are detailed from time to time in our reports filed with the SecuritiesSEC and Exchange Commission (SEC)updated as necessary, and we encourage you to consult such disclosures.

All such factors are difficult to predict, contain uncertainties whichthat may materially affect our actual results and are beyond our control.  You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.  New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.  For more information, see Item 1A "Risk, Risk Factors," included in this combined Annual Report on Form 10-K. ThisTh is Annual Report on Form 10-K also describes material contingencies and critical accounting policies and estimates in the accompanying "Management’sManagement’s Discussion and Analysis"Analysis and "CombinedCombined Notes to Consolidated Financial Statements."Statements.  We encourage you to review these items.

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PART I

Item 1.

Business

Please refer to the Glossary of Terms for definitions of defined terms and abbreviations used in this Annual Report on Form 10-K.

PROPOSED MERGER WITH NSTAR

On October 18, 2010, we and NSTAR announced that each company’s Board of Trustees unanimously approved a Merger Agreement (the merger agreement) to combine the two companies.  The transaction was structured as a merger of equals in a tax-free exchange.  Upon the terms and subject to the conditions set forth in the merger agreement, at closing, NSTAR will become a wholly-owned subsidiary of NU.  The post-transaction company will provide electric and natural gas energy delivery service to nearly 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire, representing over half of all the customers in New England.  

Under the terms of the merger agreement, NSTAR shareholders would receive 1.312 NU common shares for each common share of NSTAR that they own (the "exchange ratio").  The exchange ratio was structured to result in a no premium merger and is based on the average closing share price of each company's common shares for the 20 trading days preceding the announcement.  Following completion of the merger, common shares of the post-transaction company will be owned approximately 56 percent by NU shareholders and approximately 44 percent by former NSTAR shareholders.  We anticipate that we will issue approximately 137 million common shares to the NSTAR shareholders as a result of the merger.  Following the closing of the merger, our next quarterly dividend per common share will be increased to an amount that is equivalent to NSTAR’s last quarterly dividend per common share paid prior to the closing, divided by the exchange ratio.  Based on the last quarterly dividend paid by NSTAR of $0.425 per share, and assuming there are no changes to such dividend prior to the closing of the merger, that would result in NU’s quarterly dividend being increased by approximately 18 percent to approximately $0.325 per share, or approximately $1.30 per share on an annualized basis as compared to NU's current annualized dividend of $1.10 per share.  NU filed its joint proxy statement/prospectus with the SEC on January 5, 2011 and scheduled a special meeting of shareholders for March 4, 2011, at which shareholders will vote on whether to approve the merger.  

Completion of the merger is subject to various customary conditions, including approval by holders of two-thirds of the outstanding common shares of each company and receipt of all required regulatory approvals, including those of the Massachusetts DPU, the FERC and the NRC.  We received approval from the FCC on January 4, 2011, and on February 10, 2011, the applicable Hart-Scott-Rodino waiting period expired.  Several intervening parties have applied to participate in the regulatory review of the merger and have raised various issues that they believe the regulatory agencies should examine in the course of the proceedings.  

In November 2010, the DPUC issued a draft decision stating it lacked jurisdiction over the merger.  In December 2010, the Connecticut Office of Consumer Counsel, supported by the Connecticut Attorney General, petitioned the DPUC to reconsider its draft decision.  In January 2011, the DPUC issued an Administrative Order stating that it plans to hold a hearing to determine if it has jurisdiction over the merger.  Oral arguments surrounding the draft decision were held in February 2011.  The DPUC plans to hold an informational hearing at a date to be determined.  In addition, legislation proposing to give the DPUC jurisdiction over the merger may be introduced in the Connecticut legislature.  

THE COMPANY

NU, headquartered in Berlin,Hartford, Connecticut, is a public utility holding company registered with the Federal Energy Regulatory Commission (FERC)subject to regulation by FERC under the Public Utility Holding Company Act of 2005.  We are engaged primarily in the energy delivery business through the following wholly-owned regulated utility subsidiaries:

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The Connecticut Light and Power Company (CL&P), a regulated electric utility whichthat serves residential, commercial and industrial customers in parts of Connecticut.Connecticut;

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Public Service Company of New Hampshire (PSNH), a regulated electric utility whichthat serves residential, commercial and industrial customers in parts of New Hampshire.Hampshire and continues to own generation assets used to serve customers;

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Western Massachusetts Electric Company (WMECO), a regulated electric utility whichthat serves residential, commercial and industrial customers in parts of western Massachusetts; and

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Yankee Gas Services Company (Yankee Gas), a regulated natural gas utility whichthat serves residential, commercial and industrial customers in parts of Connecticut.

We sometimes refer to CL&P, PSNH, WMECO and Yankee Gas collectively in this Annual Report on Form 10-K as the "regulated companies."

NU also owns certain unregulated businesses through its wholly-owned subsidiary, NU Enterprises, Inc. (NU Enterprises).  We have exited most of these businesses.Enterprises.  As of December 31, 2008,2010, NU Enterprises's remainingEnterprises’ business consisted of (i) Select Energy Inc.’sEnergy’s few remaining energy wholesale marketing contracts, which are being wound down, and (ii) NU Enterprises’ remaining energy serviceselectrical contracting business.

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Although NU, consolidated, CL&P, PSNH and WMECO each report their financial results separately, we also include information in this report on a segment, or line of business basis.  The regulated companies include three business segments:line-of-business, basis - the electric distribution segment (which also includes PSNH’s regulatedthe generation activities), thebusinesses of PSNH and WMECO and our natural gas distribution segmentbusiness) and the electric transmission segment.  The regulated companies’ segment of our business representedOur Regulated companies accounted for approximately 99.599 percent of our total earnings of $387.9 million for 2008, excluding an after-tax charge of $29.8 million resulting from the settlement of litigation with Consolidated Edison, Inc. (Con Edison),2010, with electric distribution (including PSNH’s generation activities) representing approximately 42.645 percent, electric transmission representing approximately 47.6 percent, and natural gas distribution representing approximately 9.3 percent.  At December 31, 2008, the NU Enterprises business segment included the following legal entities: (i) Select Energy, Inc. (Select Energy), (ii) Northeast Generation Services Company (NGS), (iii) E.S. Boulos Company (Boulos), (iv) the8 percent and electric transmission representing approximately 46 percent of consolidated earnings.  The remaining business1 percent of Select Energy Contracting, Inc. (SECI), (iv) NGS Mechanical, Inc., and (v) NU Enterprises parent.

For information regarding each of NU’s segments, see Note 17, "Segment Information," to the Consolidated Financial Statements in this Annual Report on Form 10-K.our 2010 earnings comes from our competitive businesses.  

REGULATED ELECTRIC DISTRIBUTION

General

NU’s electric distribution segment is made upconsists of the distribution businesses of CL&P, PSNH and WMECO, which are primarily engaged in the distribution of electricity in Connecticut, New Hampshire and western Massachusetts, respectively, plus PSNH’s regulated electric generation business.business and WMECO’s solar generation.  The following table shows the sources of 20082010 electric franchise retail revenues for NU’s electric distribution companies, collectively, based on categories of customers:

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A summary of changes in the operatingRegulated companies’ retail electric kilowatt-hour (kWh) distribution sales (GWh) for the 12-months ended December 31, 20082010 as compared to December 31, 20072009 on an actual and weather normalized basis (using a 30-year average) is as follows:

RetailTotal retail electric sales for all three electric companies were higher in 2008 were lower2010 compared to 2009 due primarily to warmer than those in 2007.  The 2008normal weather normalized decrease of 2.6 percent reflects the fact that our customers are responding to the volatile costs of energy and to the economic conditions of our region and the nation.  We believe customers will continue to respond to these factors and to the recent and ongoing developments in the financial markets resultingsummer of 2010 and colder than normal weather in an estimated declineDecember 2010.  Residential sales benefitted the most from the weather in weather-normalized sales of approximately 1 percent2010 and were higher for all three electric companies in 2010 compared to 2009.  

ChangesOn a weather normalized basis, retail sales for all three electric companies were lower in electric sales, however, have less of an impact on2010 compared to 2009. We believe the earnings ofdecrease was due in part to increased conservation efforts by our electric distribution companies than in prior years because non-distribution rate revenues, which represented approximately 76 percent of electric distribution company revenues in 2008, are tracked and reconciled to actual costs.  Non-distribution rate revenues include the energy, stranded cost, retail transmission and federally mandated congestion charges (FMCC) and other components of rates.  For non-distribution rate revenues, the only impact to earnings is from carrying costs on over- or under-recoveries.  With respect to our electric distribution company revenues, about two-thirds of CL&P's and WMECO's revenues and about one-half of PSNH's revenues are recovered through charges that are not dependent on overall sales volumes, such as the customer chargecustomers and the demand charge.continuing effects of the weak economy.  

Comparable to our sales results in 2008, our uncollectibles expense has also been influenced by the adverse economic conditions of our region. Our write-offs as a percentage of revenues increased in 2008 for all our electric distribution companies. Similar to changes in our retail sales, changes in our uncollectibles expense have less of an impact on earnings of our electric distribution companies than in prior years as a portion of the uncollectibles expense for each of the electric distribution companies is allocated to its respective energy supply rate and recovered as a tracked expense.

THE CONNECTICUT LIGHT AND POWER COMPANY - DISTRIBUTION

CL&P’s distribution segment isbusiness consists primarily engaged inof the purchase, delivery and sale of electricity to its residential, commercial and industrial customers.  AtAs of December 31, 2008,2010, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut.  CL&P does not own any electric generation facilities.  In 2010, CL&P had contracts to purchase the electric output from eighteen IPP generators.  The term of two of these contracts ended in 2010.  In 2011 the sixteen remaining generators are anticipated to provide approximately two million MWh per year through March 2015, with purchase quantities dropping significantly from 2015 through 2024, when the term of the last IPP contract ends.  CL&P sells the output of these contracts into the ISO New England market, crediting customer energy charges with the proceeds.  CL& ;P has entered into eleven contracts with renewable energy generators under a state program known as Project 150, and UI has entered into 2 other similar contracts under Project 150.  CL&P and UI will share the costs and benefits of these contracts on an 80 percent and 20 percent basis, respectively.  This cost sharing split is independent of the specific utility that is the counterparty to the contract.  It is currently projected that the first of these renewable energy projects will commence commercial operation in 2011.

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The following table shows the sources of 20082010 electric franchise retail revenues for CL&P based on categories of customers:

Rates

CL&P is subject to regulation by the Connecticut Department of Public Utility Control (DPUC)DPUC, which, among other things, has jurisdiction over its rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of facilities.  CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services.

CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewables, competitive transition assessment (CTA)CTA, SBC and other charges that are assessed on all customers.  CL&P also has regulatory orders allowing it to recover all or substantially all of its prudently incurred stranded costs, which are pre-restructuring expenditures incurred, or commitments for future expenditures made, on behalf of customers with the expectation such expenditures would continue to be recoverable in the future through rates. CL&P has financed

The CTA is a significant portion of its stranded costs through the issuance of rate reduction certificates or bonds (RRBs) secured by its rightcharge assessed to recover stranded costs over time (securitization). CL&Passociated with electric industry restructuring as well as various IPP contracts.  The SBC recovers the costs of securitization through the CTA component of its rates.  In addition to those stranded costs being recovered through securitizat ion, CL&P’s stranded costs included, as of December 31, 2008, ongoing independent power producer costs and costs associated with various hardship and low income programs as well as payments to municipalities to compensate them for losses in property tax revenue due to decreases in the ongoing decommissioningvalue of the Maine Yankee, Connecticut Yankeeelectric generating facilities resulting directly from electric industry restructuring.  The CTA and Yankee Rowe nuclear units.SBC are annually reconciled to actual costs incurred, with any difference refunded to, or recovered from, customers.

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Under state law, all of CL&P's customers are entitled to choose their energy suppliers, while retaining CL&P asremains their electric distribution company.  Under "Standard Service" rates for customers with less than 500 kWKW of demand and "Supplier of Last Resort Service" rates for customers with 500 kWKW of demand or greater, CL&P purchases power for those customers who do not choose a competitive energy supplier and passes through the cost to ratepayerssuch customers through the "Generation Service Charge"a combined  GSC and the "Bypassable Federally Mandated Congestion Charge" (FMCC) componentsFMCC on customers' bills.  The combined GSC and FMCC charges for both types of service recover all of the customer’s bill, whichcosts of procuring energy from CL&P's wholesale suppliers and are adjusted periodically and reconciled on a semi-annual basis.semi-annually in accordance with the directives of the DPUC.

A large percentageAlthough more CL&P customers chose competitive energy suppliers in 2010 than in 2009, CL&P continues to supply approximately 40 percent of CL&P's customers have continued to buy their power from CL&Pits customer load at Standard Service rates or Supplier of Last Resort Service rates.  However, CL&Prates while the other 60 percent of its customer load has experienced some customer migrationmigrated to competitive energy suppliers, with the movement concentrated among larger customers.suppliers.  Because this customer migration is only for energy supply service, there isit has no impact on CL&P’s delivery business or its operating income.

Distribution Rates: On June 30, 2010, the deliveryDPUC issued a final order in CL&P’s most recent retail rate case approving annualized distribution rate increases of $63.4 million effective July 1, 2010 and an incremental $38.5 million effective July 1, 2011.  The 2010 increase was deferred from customer bills until January 1, 2011 to coincide with the decline in revenue requirements associated with the final payment of CL&P’s RRBs. In its decision, the DPUC also maintained CL&P’s authorized distribution segment regulatory ROE of 9.4 percent.  In 2010, CL&P earned a distribution segment regulatory ROE of 7.9 percent, compared to 7.3 percent in 2009, and expects to earn a distribution segment regulatory ROE of approximately 9 percent in 2011.

In May 2010, the Connecticut Legislature approved a state budget for the 2010-2011 fiscal year, which calls for the issuance by the state of Connecticut of up to $760 million of economic recovery revenue bonds (ERRBs) that would be amortized over eight years.  These bonds will be repaid through a charge on the bills of customers of CL&P and other Connecticut electric distribution companies.  For CL&P, the revenue to pay interest and principal on the bonds would come from a continuation of a portion of its CTA, which would have otherwise ended by December 31, 2010 with the businessfinal payment of the principal and interest on its RRBs, and the diversion of about one-third of the annual funding for C&LM programs beginning in April 2012.  A lawsuit pending against the DPUC to prevent the issuance of the ERRBs is pending and several bills seeking to modify or prevent the operating incomeissuance have been proposed before the state l egislature.

On March 31, 2010, CL&P filed with the DPUC an AMI and dynamic pricing plan concluding that a full deployment of AMI meters accompanied by dynamic pricing options for all CL&P.&P customers would be cost beneficial under a set of reasonable assumptions, identified as the "base case scenario."  Under the base case scenario, capital expenditures associated with the installation of the meters are estimated at $296 million.  CL&P has proposed beginning installation of meters in late 2012 and finishing in 2016.

CL&P adjustshas a transmission adjustment clause as part of its retail transmissiondistribution rates, which reconciles on a regularsemi-annual basis the transmission revenues billed to customers against the transmission costs of acquiring such services, thereby recovering all of its retail transmission expenses on a timely basis.  (See "Regulated Electric Transmission" in this Annual Report on Form 10-K).

On January 28, 2008, the DPUC approved $77.8 million, or 11.7 percent, and $20.1 million, or 2.6 percent, in annual increases in CL&P’s distribution rates, effective February 1, 2008 and February 1, 2009, respectively.  The rate decision included an ROE of 9.4 percent, with CL&P continuing its earnings sharing mechanism, which provides that ratepayers and shareholders share equally in any earnings in excess of its allowed regulatory ROE.  For further information on CL&P rates, see "Regulatory Developments and Rate Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in this Annual Report on Form 10-K.

Regulatory Update

On May 2, 2008, the DPUC approved CL&P’s revised metering compliance plan that would meet the DPUC's objective of making time-of-use rates available to CL&P customers. The DPUC decision authorized a pilot program involving the installation of advanced metering infrastructure (AMI) meters and a rate design pilot to test new time-of-use and real-time rates to determine customer acceptance and load response to various pricing structures.  CL&P expects to conduct the AMI pilot with approximately 3,000 customers during the summer of 2009.  The estimated incremental cost of the program is expected to be between $10.6 million to $13 million and such costs are authorized to be recovered from customers, initially through CL&P’s FMCC charges.  The non-incremental operating and maintenance expenses are projected to be less than $2 million.

In 2008, pursuant to Connecticut's "Act Concerning Energy Independence," (Energy Independence Act), CL&P signed five contracts and The United Illuminating Company (UI) signed two contracts, each to purchase energy, capacity and renewable energy credits from planned renewable energy plants, including biomass and fuel cell projects, approved by the DPUC, for a total of 109 MW.  CL&P had also signed one contract with a biomass project in 2007 to purchase 15 MW of its output.  Purchases under the contracts are scheduled to begin in 2009 through 2011 and to extend for periods ranging from 15 to 20 years.  As directed by the DPUC, CL&P and UI have also signed a sharing agreement under which they will share the costs and benefits of these contracts, with 80 percent to CL&P and 20 percent to UI.  On January 16, 2009, the DPUC issued a draft decision selecting two additional renewable energy project s for a total of 6 MW with which CL&P or UI will sign similar contracts.  The final decision is scheduled for March 11, 2009.  Additional projects are expected to be selected by the DPUC to achieve a total of 150 MW of additional renewable energy sources in Connecticut.  CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P's customers.

Also in 2008, CL&P and UI entered into contracts for differences (Peaker CfDs) with developers of three proposed peaking generation units totaling 506 MW of summer peaking capacity, as approved by the DPUC. The Peaker CfDs provide for the payment to the developer of the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment stream for 30 years.  As directed by the DPUC, CL&P and UI will share the net costs and benefits of the Peaker CfDs on a basis of 80 percent and 20 percent, respectively.  CL&P’s portion of the costs and benefits will be paid by or refunded to its customers

In 2008, the DPUC issued final decisions in a docket examining the manner of operation and accuracy of CL&P's electric meters and in a docket investigating CL&P billing errors involving approximately 2,000 customers on time of use rates.  In the metering docket decision, the DPUC did not fine CL&P, but held that possibility open if CL&P fails to meet benchmarks to be established in the docket. The decision in the time-of-use docket disallowed recovery from customers of the incremental costs associated either directly or indirectly with the billing errors.  These incremental costs are not material and have been expensed as incurred.

In prior years, CL&P has submitted to the DPUC its proposed methodology to calculate the variable incentive portion of its Transition Service energy procurement fee, which was effective through 2006 and had requested approval of a pre-tax $5.8 million 2004 incentive fee.  In December 2005, the DPUC issued a draft decision authorizing the $5.8 million incentive fee and CL&P recovered the $5.8 million amount by recording it in 2005 earnings through the CTA reconciliation process.  CL&P has not recorded any amounts in earnings related to the 2005 or 2006 procurement fee.  On January 15, 2009, the DPUC issued a final decision on the 2004 incentive fee that reversed its December 2005 draft decision, and concluded that CL&P was not eligible for the procurement incentive compensation for 2004.  As a result, the $5.8 million pre-tax charge was recorded in CL&P’s 2008 earnings, and an obligation to r efund the $5.8 million to customers was established in the CTA reconciliation process as of December 31, 2008.  CL&P filed an appeal of this decision on February 26, 2009.  

For further information on regulatory actions affecting CL&P, see "Regulatory Developments and Rate Matters - Connecticut - CL&P" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in this Annual Report on Form 10-K.

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Sources and Availability of Electric Power Supply

As noted above, CL&P does not own any generation assets and purchases its energy requirements to serve its Standard Service and Supplier of Last Resort Service loads from a variety of competitive sources through periodic requestsRFPs.  CL&P enters into supply contracts for proposals (RFPs).  CL&P issues RFPsStandard Service periodically for periods of up to three years to layer Standard Service full requirements supply contracts in order to mitigate price volatility for its residential and small and medium load commercial and industrial customers.  CL&P issues RFPsenters into supply contracts for Supplier of Last Resort service for larger commercial and industrial

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customers every three months.  Currently, CL&P has contracts in place contracts with various suppliers through 2010 for all of its Standard Service loads through 2011, 40 percent of expected load for 2012, and to date one tranche has been filled10 percent of expected load for 2013.  CL&P’s contracts for its Supplier of Last Resort Service loads extend through the second quarter of 2011.

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE - DISTRIBUTION

PSNH’s distribution segmentbusiness (which includes its regulated generation) isgeneration business) consists primarily engaged inof the generation, purchase, delivery and sale of electricity to its residential, commercial and industrial customers.  AtAs of December 31, 2008,2010, PSNH furnished retail franchise electric service to approximately 493,000497,000 retail customers in 211 cities and towns in New Hampshire.  PSNH also owns and operates approximately 1,200 MW of primarily fossil-fueled electricity generation assets.  Approximately 70 MW ofIncluded in those generation assets are hydroelectric units. Included among these generating assets is aits 50 MW wood-burning generating unit (Northern WoodsNorthern Wood Power Project)Project at its Schiller Station in Portsmouth, New Hampshire, and approximately 70 MW of hydroelectric generation.  PSNH also has contracts with 18 IPPs, the output of which was converted fromit either uses to serve its customer load or sells into the market.

PSNH is constructing its Clean Air Project, a coal-burning unitsulfur dioxide and mercury scrubber at its Merrimack coal-fired generation station, which is currently expected to cost $430 million.  The project is scheduled for completion in December 2006.mid-2012.  PSNH will recover all related costs through its ES rates described below.

The following table shows the sources of 20082010 electric franchise retail revenues based on categories of customers:

Rates

PSNH is subject to regulation by the New Hampshire Public Utilities Commission (NHPUC)NHPUC, which has jurisdiction over, among other things, rates, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service, management efficiency and construction and operation of facilities.

PSNH’s Energy Service (ES)ES rate recovers PSNH'sits generation and purchased power costs includingfrom customers on a current basis and allows for an ROE of 9.81 percent on PSNH'sits generation assets.  PSNH files for approval of updated ES rates annually with the NHPUC, with a six-month true-up, to ensure timely recovery of its costs.  PSNH defers for future recovery or refund any difference between its ES revenues and the actual costs incurred.

On July 1, 2008, PSNH’s Delivery Service (DS) rates decreased by $0.4 million annually.  This amount consisted of a $3.4 million rate reduction related to the full recovery of a rate differential recoupment and an increase of approximately $3 million per year for a two-year period effective July 1, 2008 to eliminate a negative balance in the major storm cost reserve and restore the intended reserve level of $1 million.

Pursuant to a distribution and transmission rate case settlement agreement between PSNH, the NHPUC staff and the Office of Consumer Advocate, the NHPUC approved PSNH’s petition seeking to establish a Transmission Cost Adjusting Mechanism (TCAM) rate to be reset annually consistent with the rate settlement agreement.  On May 13, 2008, PSNH filed a July 1, 2007 through June 30, 2008 TCAM reconciliation and a projected TCAM rate to be billed effective July 1, 2008 related to July 1, 2008 through June 30, 2009 TCAM costs.investment.  

Under New Hampshire law, the Stranded Cost Recovery Charge (SCRC)SCRC allows PSNH to recover its stranded costs, including expenses incurred throughunder mandated power contracts and other long-term investments and obligations.  PSNH has financed a significant portion of its stranded costs through securitization by issuing RRBs secured by the right to recover these stranded costs from customers over time.  Ittime and recovers the costs of these bonds through the SCRC rate.  

On an annual basis, PSNH makesfiles with the NHPUC an ES/SCRC reconciliation filing withfor the preceding year.  The difference between ES/SCRC revenues and ES/SCRC costs are included in the ES/SCRC rate calculations and refunded to/recovered from customers in the subsequent period approved by the NHPUC.  

The TCAM allows PSNH to recover on a fully reconciling basis its transmission related costs.  The TCAM is adjusted July 1 of each year.

Distribution Rates:  On June 28, 2010, the NHPUC for the previous year.  For further informationapproved a joint settlement of PSNH’s rate case that had commenced in 2009, allowing a net distribution rate increase of $45.5 million on PSNH rates, see "Regulatory Developmentsan annualized basis to be effective July 1, 2010, and Rate Matters" in Item 7, "Management's Discussionannualized distribution rate adjustments projected to be a decrease of $2.9 million and Analysisincreases of Financial Condition$9.5 million and Results$11.1 million on July 1 of Operations," in this Annual Report on Form 10-K.

Under the terms of the order issued by the NHPUC approving PSNH’s Northern Wood Power Project, which replaced oneeach of the three 50 MW boiler unitssubsequent years, respectively.  PSNH agreed not to file a new distribution rate request that would be effective prior to July 1, 2015.  During the term of the settlement, PSNH can only propose changes to its permanent distribution rate level when its 12-month distribution ROE falls below 7 percent for two consecutive quarters or certain specified external events, such as major storms, occur.  If PSNH’s 12-month ROE rolling average is greater than 10 percent, anything over the 10 percent level will be all ocated 75 percent to customers and 25 percent to PSNH.  The settlement also provided that the authorized regulatory ROE on distribution only plant will continue at the coal-fired Schiller Station, certain revenue, credits and cost avoidances (revenue sources) are shared between PSNH and its customers.  These revenue sources include salespreviously allowed level of renewable energy certificates (RECs)9.67 percent.  PSNH’s distribution segment regulatory ROE was 10.2 percent (including generation) in 2010, compared to other utilities, brokers, or suppliers, and production tax credits.  In any given year, if the combination of revenue sources falls short of a stipulated revenue level, PSNH and its customers each share half of any deficiency, and if the combination exceeds the stipulated revenue level, PSNH and its customers each share half of any excess.  The Northern Wood Power Project entered commercial operation on December 1, 2006, and revenue sources exceeded stipulated levels7.2 percent in 2008 due to its performance and favorable pricing2009.  We expect PSNH’s distribution segment regulatory ROE will be approximately 9 percent in the Massachusetts and Rhode Islan d markets for the RECs.  As a result, customers and shareholders will share equally a benefit of about $7.8 million of incremental revenues for 2008.  2011.

Although PSNH's customers are entitled to choose competitive energy suppliers, with PSNH hasproviding default energy service under its ES rate for those customers who do not elect to use a third party supplier.  Prior to 2009, PSNH experienced only a smallminimal amount of customer migration.  However, customer migration levels began to date.increase significantly in 2009 as energy costs decreased from their historic high levels and competitive energy suppliers with more pricing flexibility were able to offer electricity supply at lower prices than PSNH.  By the end of 2010, approximately 2 percent of all of PSNH’s customers (approximately 32 percent of load), mostly large commercial and industrial customers, had switched to competitive energy suppliers.  The increased level of migration has caused an increase in the ES rate, as fixed costs of PSNH’s generation assets must be spread over a smaller group of customers and lower sal es

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On December 11, 2008,volume.  The customers that did not switch to a major ice storm struck portionsthird party supplier, predominately residential and small commercial and industrial customers, are now paying a larger proportion of New England, severely damaging PSNH’s distribution systems. This was the most severe ice storm in PSNH’s history.  Of the 440,000 New Hampshire homes and businesses that lost power, 322,000 were served by PSNH.  Restoration operations commenced on December 11, 2008 and were substantially completed by December 25, 2008.  PSNH utilized its own line crews, local contractors, line crews from other NU subsidiaries and numerous other line crews from the eastern United States and Canada.these fixed costs.

The operating costNHPUC opened a proceeding in 2010 to consider the effect of storm restorations that meet acustomer migration on ES rates for customers, principally residential and small commercial and industrial customers, remaining on PSNH default energy service.  As part of this docket, the NHPUC specified criteriastated its intention to explore the interplay of customer choice, migration issues and power procurement options for PSNH.

PSNH cannot predict if the upward pressure on ES rates will continue into the future, as future customer migration levels, which are funded throughdependent on market prices and supplier alternatives, are uncertain.  If future market prices once more exceed the Major Storm Costs Reserve (MSCR).  Capital costs for any storm work are charged to property, plant and equipment and are recovered through the normal distribution ratemaking process.  As the December 2008 ice storm met the MSCR criteria, $62.7 million of total estimated repair costs of $75 million associated with this storm were charged to the MSCR at December 31, 2008.  PSNH intends to request recoveryaverage ES rate level, some or all of these costs as part of its next delivery rate proceeding with the NHPUC.  Out of the remaining total storm costs incurred through December 31, 2008, $6.5 million has been expensed and $5.6 million has been capitalizedcustomers on third party supply may migrate back to plant and equipment.  PSNH expects to recognize an additional $10 million in 2009 when the weather is warmer and additional clean-up and repairs can be performed.  We carry $15 milli on of storm-related insurance system-wide and to the extent that any insurance proceeds are received, a portion would be allocated to PSNH to reduce the amount of deferred or expensed storm costs.

Regulatory Update

In 2006, New Hampshire enacted a law requiring PSNH to reduce the mercury emissions for its coal fired plants by at least 80 percent (with co-benefits of reduction in sulfur dioxide (SO2) emissions as well).  Wet scrubber technology will be installed at Merrimack Station in Bow New Hampshire no later than July 1, 2013.  Following an August 2008 announcement by PSNH that the cost of this installation would be increasing from the original estimate of $250 million to $457 million, the NHPUC opened an inquiry to determine whether it had authority to assess whether the project is in the public interest.  In September 2008, the NHPUC ruled that its authority is limited to determining at a later time the prudence of the costs incurred in complying with the legislation.  In October 2008, several parties filed motions with the NHPUC requesting a reconsideration of its ruling; these motions were rejected.  On December 11 , 2008, several parties involved in the filing of the October 2008 motion for a rehearing filed an appeal with the New Hampshire Supreme Court requesting that the Court overturn the NHPUC finding that it lacked present authority over this matter.  The Supreme Court has indicated that it will hear this appeal, but has not yet issued a schedule for oral arguments.  

In July 2008, New Hampshire passed a law establishing a transmission commission responsible for developing a proposal to expand the electric transmission system in northern New Hampshire to encourage the development of new renewable generation sources.  On December 1, 2008, the transmission commission submitted its progress report, which concluded that New Hampshire should continue to pursue the upgrade of transmission capacity in its northern region to allow development of its native renewable energy resources.  Also, the transmission commission should continue to pursue both local and regional cost allocation issues related to the transmission expansion.  We believe the northern New Hampshire region has the potential for over 500 MW of new renewable resources.  PSNH has included $130 million in its 2009 to 2013 capital plan for transmission upgrades in the region which assumes that these projects are built and a c ost allocation solution can be agreed to by relevant parties.

In July 2008, New Hampshire passed a law authorizing rate recovery by electric public utilities of investments made in distributed energy resources up to 5 MW, such as renewable energy generation.  The total investment is limited to resources having a capability equal to 6 percent of a distribution utility’s peak load.  PSNH has not yet included any distributed energy resource investment opportunities in its capital expenditure plans.PSNH.  

Sources and Availability of Electric Power Supply

During 2008,2010, about 6788 percent of PSNH’s load was met through its own generation, and long-term power supply rateprovided pursuant to orders of the NHPUC, and contracts with third parties.  The remaining 3312 percent of PSNH's load was met by short-term (less than one year) purchases and spot purchases in the competitive New England wholesale power market.  PSNH expects to meet its load requirements in 20092011 in a similar manner.  

New Hampshire’s "Renewable Energy Act" establishes renewable portfolio standards for electricity sold in the state that require annual increases in the percentage of the electricity sold to retail customers having direct ties to renewable sources.  The renewable sourcing requirements began in 2008 and increase each year to reach 23.8 percent by 2025.  PSNH plans to meet these standards, in part, through the purchase of Renewable Energy Certificates (RECs) from qualified renewable energy resources.  For each MWH of energy produced from a qualifying resource, the producer will receive one REC. Energy suppliers, like PSNH, will purchase these RECs from the producers and will use them to satisfy the RPS requirements.  To the extent that PSNH is unable to purchase sufficient RECs, it will be required to make up the difference between the RECs purchased and its total obligation by making an alternative comp liance payment (ACP) for each REC requirement for which PSNH is deficient.  The costs of both the RECs and ACPs do not impact earnings, as these costs are being recovered by PSNH through its ES rates.  For further information, see "Regulatory Developments and Rate Matters - New Hampshire" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in this Annual Report on Form 10-K.

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WESTERN MASSACHUSETTS ELECTRIC COMPANY - DISTRIBUTION

WMECO’s distribution segment is engaged inbusiness consists primarily of the purchase, delivery and sale of electricity to residential, commercial and industrial customers.  At December 31, 2008,2010, WMECO furnished retail franchise electric service to approximately 206,000 retail customers in 59 cities and towns in the western third of Massachusetts.  Following electric industry restructuring in the 1990s, WMECO does not own anysold all of its generating facilities and now purchases its energy requirements from competitive suppliers.  In 2009, pursuant to the Massachusetts Green Communities Act, WMECO was authorized to install 6 MW of solar energy generation in its service territory.  In October 2010, WMECO completed construction of a 1.8 MW solar generation facility at a site in Pittsfield, Massachusetts, which began producing electricity generating facilities.  Onin late 2010.  In January 2011, WMECO announced its plans to develop a second solar generation faci lity at a site in Springfield, Massachusetts.  This facility will accommodate 17,000 solar panels, producing up to 4.2 MW of solar energy.  WMECO will sell all energy and other products from its solar generation facilities into the ISO New England market. WMECO had a contract with one IPP generator in 2010, the output of which WMECO sold into the ISO New England market.  The term of this contract ended on December 31, 2008, WMECO purchased all of the transmission-related assets of its affiliates, Holyoke Water Power Company (HWP) and Holyoke Power and Electric Company (HP&E) for approximately $4 million.2010.

The following table shows the sources of 20082010 electric franchise retail revenues based on categories of customers:

Rates

WMECO is subject to regulation by the Massachusetts Department of Public Utilities (DPU),DPU, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, acquisition of securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities.  WMECO's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services.  Massachusetts utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to coverrecover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.

Under state law, all of WMECO's customers are now entitled to choose their energy suppliers, while retaining WMECO asremains their distribution company.  WMECO purchases electric power from competitive suppliers for, and passes through the cost to, those customers who do not choose a competitive energy supplier (basic service).  Basic service charges are adjusted and reconciled on an annual basis.  Most of WMECO's residential and smallersmall commercial and industrial customers have continued to buy their power from WMECO at basic service rates.  A greater proportion of large commercial and businessindustrial customers have opted for a competitive energy supplier.

WMECO collects its transmission costs through a transmission adjustment clause, which is adjusted annually, thereby allowing WMECOcontinues to recover allsupply approximately 50 percent of its retail transmission expensescustomer load at basic service rates while the other 50 percent of its customer load has migrated to competitive energy suppliers.  Because this customer migration is only for energy supply service, it has no impact on a timely basis.WMECO’s delivery business or its operating income.

WMECO also has regulatory orders allowing it to recover all or substantially all ofrecovers certain costs through various tracking mechanisms in its retail rates, including transmission costs, pension costs and prudently incurred stranded costs. WMECO has financed acosts (a portion of its stranded costswhich have been financed through securitization by issuing RRBs secured by the right to recover stranded costs from customers over time.  It is recovering the costs of securitization through rates.RRBs) with periodic true-up adjustments.  

On January 1, 2008, WMECO’s distribution rates increased by $3 million annually as approved by the Massachusetts DPU in December 2006.  WMECO adjusted its rates to include the distribution increase, new basic service contracts, and changes in several tracking mechanisms.  On December 29 and 30, 2008, the DPU approved WMECO’s proposed rate changes effective January 1, 2009.  The rate changes were made in accordance with WMECO’s various tracking mechanisms.

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The major ice storm on December 11, 2008 also impacted parts of Massachusetts, including areas served by WMECO.  As this storm met the storm costs reserve criteria approved in WMECO’s last distribution rate case settlement, $11.3 million of the total $13.8 million estimated repair costs associated with this storm were recognized as a deferred asset at DecemberDistribution Rates:    On January 31, 2008.  WMECO expects to begin recovery of these costs in its next distribution rate proceeding.  The DPU has opened a formal docket to review storm restoration efforts by the state's utilities.

For further information on WMECO’s rates, see "Regulatory Developments and Rate Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in this Annual Report on Form 10-K.

Regulatory Update

On July 16, 2008,2011, the DPU issued a final decision in its decoupling generic docket requiring all gasWMECO’s July 2010 rate application, granting a $16.8 million annualized rate increase in distribution revenues and electric utilities to filean allowed ROE of 9.6 percent effective February 1, 2011.  The DPU also authorized a full decoupling proposalsmechanism, whereby actual revenue billed by WMECO would be reconciled with their next generalWMECO’s target revenue on an annual basis, WMECO’s request to recover balances of certain active hardship account balances and the recovery of certain storm costs over five years.  The DPU did not authorize rate case.  The decision rejected calls for partial decoupling or decoupling by rate designrecovery of a proposed $20 million average increase in favor of full decoupling by rate class.  On September 2, 2008, WMECO notified the DPU that it expectsWMECO’s capital spending plan. WMECO’s distribution segment regulatory ROE was 4.6 percent in 2010 compared to file its next8.4 percent in 2009.  We expect WMECO’s distribution rate casesegment regulatory ROE will be approximately 9 percent in mid-2010 to be effective January 1, 2011.  That case will include a proposal to fully decouple distribution revenues from kilowatt-hour sales.

As part of WMECO’s December 2006 rate case settlement agreement approved by the DPU, WMECO becameis subject to service quality (SQ)SQ metrics that measure safety, reliability and customer service.  Anyservice, and WMECO pays any charges incurred are paidfor failure to customers through a method approved by the DPU.meet such metrics to customers.  WMECO will likelynot be required to pay an assessment charge for its 2008 reliability2010 performance against the metrics established for 2008, primarilyresults as a result of significant storm activity.  WMECO has performed at target for other non-storm related reliability metrics.  WMECO will fileall of its 2008 SQ results and assessment calculation with the DPUmetrics in March 2009.  In 2008, WMECO recorded an estimated pre-tax charge and a regulatory liability of approximately $1.3 million for this assessment.

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In July 2008, Massachusetts enacted "The Green Communities Act of 2007."  Aimed at increasing energy efficiency (EE) and the use of renewable resources in the state, the Act contains many provisions important to the state’s utilities.  In addition to adopting RGGI requirements, the Act:2010.  

·

Removes the cap on utility expenditures for EE and demand response (DR).  

·

Requires utilities to file three-year EE and DR plans with a newly created Energy Efficiency Council;

·

Requires utilities to sign long-term contracts for renewable resources;

·

Allows each utility to own and operate up to 50 MW of solar generation;

·

Requires utilities to file a plan with the DPUOn October 16, 2009, WMECO filed its proposal for a dynamic pricing smart grid pilot; and

·

Increases penalties for failure to meet service quality standards from 2 percent of transmission and distribution revenues to 2.5 percent.

By April 30, 2009, WMECO is required to prepare a three-year EE and DR investment plan related to the cost of EE and DR programs established by the Act for review by the Energy Efficiency Council and, ultimately, the DPU.  In addition, WMECO filed ameter pilot program with the DPU on February 11, 2009 providing forDPU.  However, the Company does not expect it will conduct a three-phase solar generation program subject to DPU authorizationpilot prior to each phase. The initial phase calls for 6 MW of solar generation to be installed at eight host sites in WMECO's service territory upon receipt of DPU approval.  This phase of the project is expected to be completed as early as 2010 at a cost of approximately $42 million.  The second phase includes an additional 9 MW extending through 2012, and the third and final phase could increase total capacity to the 50 MW maximum.  The DPU has six months to issue a decision on WMECO's plan.  WMECO is otherwise precluded from making new generation investments, but has not yet included any solar generation investment opportunities in its capital expenditure plans.  2012.

Sources and Availability of Electric Power Supply

As noted above, WMECO does not own any generation assets (other than its recently constructed solar generation) and purchases its energy requirements from a variety of competitive sources through periodic RFPs.  For basic service power supply, WMECO issues RFPs periodically, consistent with DPU regulations. On May 14, 2008, WMECO entered into an agreement to secure 50 percent of residential, small commercial and industrial, and street lighting loads for the July 1, 2008 through June 30, 2009 period, and on November 3, 2008 WMECO entered into an agreement to secure power for half of its residential, small commercial and industrial, and street lighting loads for the January 1 through December 31, 2009 period.  WMECO will issue an RFP in the second quarter of 2009 to secure the remaining 50 percent of its residential, small commercial and industrial, and street lighting loads for the July 1 through December 31, 2009 period and 50 percent of the load for January 1, 2010 through June 3 0, 2010.  For its large commercial and industrial customers, WMECO entered into an agreement on November 3, 2008 to secure power for the first quarter of 2009 and an agreement to secure power for the second quarter 2009 on February 10, 2009.  RFPs will be issued quarterly to secure power for the balance of the year.

REGULATED GAS DISTRIBUTION – YANKEE GAS SERVICES COMPANY

Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers (approximately 200,000)206,000 customers in 71 cities and towns), and size of service territory (2,088(2,187 square miles).  Total throughput (sales and transportation) in 2008both 2010 and 2009 was 49.8 billion cubic feet (Bcf) compared with 49.7 Bcf in 2007.approximately 52.5 Bcf.  Yankee Gas provides firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on gas for their heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from Yankee Gas.  Retail natural gas service in Connecticut is partially unbundled: residential customers in Yankee Gas’ service territory buy gas supply and delivery only from Yankee Gas alsowhile commercial and industrial customers have choice in their gas suppliers.  Yankee Gas offers firm transportationtransportat ion service to its commercial and industrial customers who purchase gas from sources other than Yankee Gas as well as interruptible transportation and interruptible gas sales service to those certain commercial and industrial customers that have the capability to switch from natural gas to a nan alternative fuel on short notice.  Yankee Gas can interrupt service to these customers during peak demand periods or at any other time to maintain distribution system integrity.  In 2007, Yankee Gas completed construction ofalso owns a liquefied natural gas (LNG)1.2 Bcf LNG facility in Waterbury, Connecticut.  The LNG facility is capableConnecticut, which enables the company to buy natural gas in periods of storing the equivalent of 1.2 Bcf of natural gas.low demand, store it and use it during peak demand periods when prices are typically higher.

Yankee Gas earned $27.1 million on total gas operating revenues of approximately $577.4 million for 2008. The following table shows the sources of 2008 total2010 gas operating revenues:revenues based on categories of customers:

For more information regarding Yankee Gas’s financial results, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," and Item 8, "Financial Statements and Supplementary Data," which includes Note 17, "Segment Information," contained within this Annual Report on Form 10-K.

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A summary of changes in Yankee Gas firm natural gas sales in million cubic feet for 2008Yankee Gas for 2010 and 2009 and the percentage changes in 2010 as compared to 20072009 on an actual and weather normalized basis (using a 30-year average) is as follows:

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Yankee Gas’ firm natural gas sales are subject to many of the same influences as our retail electric sales, but they have recently benefitted from a favorable price for natural gas relative to competing fuels resulting in commercial and industrial customers switching from interruptible service to firm service, and the addition of gas-fired distributed generation in Yankee Gas’ service territory.  Actual firm natural gas sales in 2010 were higher than 2009 despite the milder weather during the first quarter 2010 heating season.  Firm natural gas sales for 2008 were higher than 2007.benefitted from these trends and from a large commercial customer who began to take service from Yankee Gas mid-way through the third quarter of 2009 and continued to take service throughout all of 2010.

In April 2010, Yankee Gas commenced construction of its WWL project, a 16-mile gas pipeline between Waterbury and Wallingford, Connecticut coupled with the increase of vaporization output of its LNG plant.  The 2008 results reflect warmer weather inproject is expected to cost approximately $57.6 million.  In 2010, approximately $26.6 million was spent on construction of the first quarter, colder weatherWWL project, which included construction of a segment of pipeline connecting the Cheshire and Wallingford distribution systems.  The remainder of the pipeline construction and the expansion of the vaporization capacity of the LNG facility are expected to be completed in the fourth quarter and an increase in industrial sales primarily due to customer-owned gas-fired distributed generation and favorable natural gas prices relative to oil.  We have assumed an increase in weather normalized firm natural gas sales of approximately 2.5 percent in 2009.  Similar to our electric distribution companies, Yankee Gas recovers a significant portion of its distribution revenues (approximately 40 percent) through charges that are not dependent on usage.

Although Yankee Gas is not subject to the FERC's jurisdiction, the FERC has limited oversight with respect to certain reporting and intrastate gas transportation that Yankee Gas provides.  In addition, the FERC regulates the interstate pipelines serving Yankee Gas’s service territory.2011

Rates

Yankee Gas is subject to regulation by the DPUC, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities.

Distribution Rates:  On January 7, 2011, Yankee Gas recovers its cost of gas supplied to customers through a Purchased Gas Adjustment (PGA) clause in its rate tariff. In 2005 and 2006,filed an application with the DPUC issued decisions requiring an auditto raise natural gas distribution rates by an independent party of approximately $11$32.8 million, in previously recovered PGA revenues associated with unbilled sales and revenue adjustments for the period of September 1, 2003 through August 31, 2005.  On June 11, 2008, the DPUC issued a final order pursuantor 7.3 percent, to which Yankee Gas was required to refund to customers approximately $5.8 million in recoveries under its Purchased Gas Adjustment clause.  Yankee Gas results for 2008 reflect an after-tax charge of $3.5 million associated with that decision.

Under a settlement of its distribution rate filing with the Connecticut Office of Consumer Counsel and the DPUC’s Prosecutorial Division, Yankee Gas’s base rate increased,be effective July 1, 2007,2011, and by $22an additional $13 million, or 4.22.8 percent, net of expected pipeline and commodity cost savings resulting primarily from completion of Yankee Gas’s LNG facility, andto be effective July 1, 2012.  Among other items, Yankee Gas was allowed anrequested to maintain its current authorized ROE of 10.1 percent.percent, that $57.6 million of costs associated with the WWL project be placed into rates, and that a substantial increase in capital funding to replace bare steel and cast iron pipe on Yankee Gas' system.  A final decision is expected in June 2011. Yankee Gas’ regulatory ROE was 8.6 percent in 2010 compared to 6.6 percent in 2009.  We expect Yankee Gas’ distribution segment regulatory ROE to be approximately 9 percent in 2011.

Sources and Availability of Natural Gas Supply

The DPUC requires that Yankee Gas will returnmeet the needs of its firm customers under all weather conditions.  Specifically, Yankee Gas must structure its portfolio to ratepayers 100 percent of all earningsmeet firm customer needs under a design day scenario (defined as the coldest day in excess30 years) and under a design year scenario (defined as the average of the allowed 10.1 percent ROE. As a resultfour coldest years in the last 30 years).  Yankee Gas’ LNG facility enables Yankee Gas to buy natural gas in periods of low demand, store it and use it during peak demand periods when prices are typically higher.  Yankee Gas’ on-system stored LNG and underground storage supplies help to meet consumption needs during the base rate increase,coldest days of winter.  Yankee Gas obtains its interstate capacity from the amount of gas supply costs charged to customers throughthree interstate pipelines that currently directly serve Connecticut: the PGA decreased.Algonquin, Tennessee and Iroquois Pipelines.  Yankee Gas has long-term firm contracts for capacity on TransCanada Pipelines Li mited pipeline, Vector Pipeline, L.P., Tennessee Gas Pipeline, Iroquois Gas Transmission Pipeline, Algonquin Pipeline, Union Gas Limited, Dominion Transmission, Inc., National Fuel Gas Supply Corporation, Transcontinental Gas Pipeline Company, and Texas Eastern Transmission, L.P. pipelines.  Yankee Gas considers such transportation arrangements adequate for its needs.

FORWARD CAPACITY MARKETS

On December 1, 2006, a FERC-approved Forward Capacity Market (FCM) settlement agreement was implemented, and the payment of fixed compensation to generators began.  The second forward capacity auction concluded on December 10, 2008 for the capacity year June 2011 through May 2012.  The bidding reached the established minimum of $3.60 per kilowatt-month with 4,755 MW of excess remaining capacity.  This means the effective price will be $3.12 per kilowatt-month compared to the equivalent first forward capacity auction price of $4.25 per kilowatt-month for the 12-month capacity period ending May 31, 2011 and $4.10 per kilowatt-month for the 12-month capacity period ending May 31, 2010.  These costs are recoverable in all jurisdictions through the currently established rate structures.

REGULATED ELECTRIC TRANSMISSION

General

CL&P, PSNH and WMECO and most other New England utilities, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region's generation and transmission facilities and the rules by which they participate in the wholesale markets and acquire transmission services.  Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent fromof all market participants, has served since 2005 as the Regional Transmission Operator (RTO)RTO of the New England Transmission System since February 1, 2005.transmission system.  ISO-NE works to ensure the reliability of the system, administers, subject to FERC approval, the independent system operator tariff, subject to FERC approval, oversees the efficient and competitive functioning of the regional wholesale power market and determines which costs of ourall regional major transmission facilities are regionalizedshared by consumers throughout New England.

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Wholesale Transmission Rates

Wholesale transmission revenues are based onrecovered through formula rates that are approved by the FERC.  Most of our wholesaleOur transmission revenues are collected under ISO-NE’s FERC Electric Tariff No. 3, Transmission, Markets and Services Tariff (Tariff No. 3).  Tariff No. 3 includes the Regional Network Service (RNS) and Local Network Service (LNS) rate schedules, among other things.  The RNS rate, administered by ISO-NE and billed to allrecovered from New England customers through ISO-NE charges which recover costs of transmission and other transmission-related services provided by all regional transmission owners, is reset on June 1stwith a portion of each yearthose revenues collected from the distribution segments of CL&P, PSNH and recovers the revenue requirements associated with transmission facilities that benefit the New England region.  The LNS rate, which we administer, is reset on January 1st and June 1st of each year and recovers the revenue requirements for local transmission facilities and other transmission costs not covered under the RNS rate, including 100 percent of the construction costs of the New England East-West Solutions (NEEW S) projects.  Both the LNS and RNS rates provide for annual true-ups to actual costs.  The LNS rate calculation recovers total transmission revenue requirements net of revenues received from other sources (i.e. RNS, rental, etc.), thereby ensuring that we recover all regional and local revenue requirements as described in Tariff No. 3.WMECO.

FERC ROE Decision

On March 24, 2008,Pursuant to a series of orders involving the ROE for regionally planned New England transmission projects, the FERC issued an order on rehearing confirming its initial order settingset the base ROE on transmission projects for the New England transmission owners, including NU’s subsidiaries.  Including a final adjustment, the order provides a base ROE ofat 11.14 percent and approved incentives that increased the ROE to 12.64 percent for the period beginning November 1, 2006. The order also affirmed FERC’s earlier decision granting a 100 basis point adder for new transmissionthose projects that are built as part of the ISO-NE Regional System Plan and are "completed and on line" by December 31, 2008.  In order to receive incentives for projects completed after December 31, 2008, transmission owners are required to make project-specific incentive requests that meet the nexus requirements under FERC guidelines for new projects. In 2008, we recognized $6 million in transmission segment earnings related to this order.  This order has been appealed to the D.C. C ircuit Court of Appeals by various state regulators and consumer advocates.  The court has set a schedule for the briefing to be concluded in the second quarter of 2009, with no date set for argument.

On May 16, 2008, CL&P filed an application with the FERC to receive ROE incentives for its portions of the Middletown-Norwalk project seeking a waiver of the "completed and on line" date of December 31, 2008 to earn the ROE incentives. Alternatively, CL&P asked FERC to find that this project met the nexus test requirements for incentives under FERC’s guidelines for new projects, and also requested an additional 50 basis point adder for advanced technology used in the project.  FERC subsequently granted the waiver request and approved the 100 basis point incentive for the entire Middletown-Norwalk project.  The FERC also found that the project met the nexus test, and granted an additional 50 basis point adder for the advanced technology aspects of the 24-mile underground portion of the project. CL&P completed the projectwere in-service by the end of 2008.  The 50 basis point adder results inIn addition, certain projects were granted additional ROE incentives by FERC under its transmission incentive policy.  As a totalresult, CL&P earns between 12.64 percent and 13.1 percent on its major transmission projects.  All appeals of FERC's orders on the ROE for th e underground portion of the Middletown-Norwalk project of 13.1 percent, which represents the overall ROE limit established by FERC.  Certain state regulators and municipal utilities had sought rehearing which was denied by FERC and Connecticut state regulatorsNew England transmission owners have since appealed the order to the D.C. Circuit Court of Appeals.  been denied.  

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On November 17, 2008, the FERC issued an order granting certain incentives and rate amendments to National Grid USA (National Grid) and us for certain components of the proposed NEEWS projects.project, which is described below.  The approved incentives includedinclude (1) an ROE of 12.89 percent, which includes an incentive of 125 basis points;percent; (2) inclusion of 100 percent construction work in progress (CWIP)CWIP costs in rate base; and (3) full recovery of prudently incurred costs if any portion of NEEWS is abandoned for reasons beyond our or National Grid's control.  Our portion of the components that received these incentives is estimated to cost approximately $1.41 billion of our $1.49 billion share of the total NEEWS projects.  Several parties have sought rehearing of this FERC order on which FERC has not yet acted.

Transmission Projects

InNEEWS

CL&P and WMECO are continuing to develop and build the NEEWS project, which is comprised of GSRP, the Interstate Reliability Project and the Central Connecticut Reliability Project, and is estimated to cost $1.52 billion in the aggregate (approximately $1.45 billion reflecting the impact of UI’s potential investment of up to approximately $69 million as discussed below).  CL&P and WMECO commenced substation construction on GSRP in December 2008, we completed2010 and expect to begin overhead line construction in the lastfirst half of our four southwest Connecticut transmission upgrades. The first of those projects, a new 345KV/115KV overhead and underground line between Bethel, Connecticut and Norwalk, Connecticut, was2011.  We expect GSRP to be placed in service in October 2006.  The remaining three projects were placed in service in 2008.  The Middletown-Norwalk project, a 69-mile, 345KV/115 KV transmission project from Middletown to Norwalk, Connecticut constructed jointly with UI, was completed in December 2008. CL&P's portion of this project cost approximately $950 million, $100 million lower than our earlier cost estimate.  The 45-mile overhead section of the project entered service on August 28, 2008 and the 24-mile underground section entered service on December 16, 2008.  The Glenbrook Cables project, a two-cable, nine-mile, 115 KV underground transmission project between Norwalk and Stamford, Connecticut entered ser vice on November 11, 2008late 2013 at a project cost of approximately $239 million, $16 million higher than previous estimates due to increased construction costs to remove underground obstacles.  The Long Island Replacement Cable project, a 138KV, 11-mile undersea transmission project between Norwalk, Connecticut and Northport-Long Island, New York was completed in September 2008.  CL&P owns 51 percent of the project, with Long Island Power Authority owning the remainder, and CL&P's portion of the project costs is anticipated to be approximately $78$795 million.

In October 2008, we commenced state regulatory filings for our next series of major transmission projects, NEEWS.  That series of projects involves our construction of new overhead 345 KV lines in MassachusettsCL&P is designing and Connecticut as well as associated substation work and 115 KV rebuilds.  One of the projects will connect to a new transmission line that National Grid plans to build in Rhode Island and Massachusetts.  On September 24, 2008, the New England Independent System Operator (ISO-NE) issued its final technical approval of the NEEWS projects which was a precursor to the siting application process.  We estimate that CL&P’s and WMECO’s total capital expenditures for these projects will be $1.49 billion through 2013.  

The first of the NEEWS projects, the Greater Springfield Reliability Project, which involves a 115 KV/345 KV line from Ludlow, Massachusetts to North Bloomfield, Connecticut, is the largest and most complicated project within NEEWS.  This project is expected

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to cost approximately $714 million if built according to our preferred route and configuration.  CL&P filed its application to build the Connecticut portion of the Greater Springfield Reliability Project with the Connecticut Siting Council (Siting Council) on October 20, 2008 and WMECO filed its application to build its portion of the project with the Massachusetts Energy Facilities Siting Board on October 27, 2008.  The Connecticut Energy Advisory Board is currently reviewing Connecticut-based generation, demand side management and other proposed alternatives to the Greater Springfield Reliability Project, which must be submitted to the Siting Council by March 19, 2009.  The Siting Council has preliminarily set dates for hearings, public comments and site visits on the Connecticut portion of the project in the second quarter of 2009.  If the overall project is approved in 2010 as expected, we currently expect to commence construction in late 2010 and place the project in service in 2013.

Our second major NEEWS project isbuilding the Interstate Reliability Project which is being designed and built in coordination with National Grid.  CL&P's shareGrid USA, whose segment of this project includes a 40-mile 345 KV line from Lebanon, Connecticut tophase will interconnect with CL&P’s at the Connecticut-Rhode Island border where it would connect with enhancements National Grid is designing.border.  In August 2010, ISO-NE reaffirmed the need for the Interstate Reliability Project.  We expect CL&P's share of the costs of this project to cost approximately $250 million.  Municipal consultations concluded in November 2008,be $301 million and CL&P plans to file siting applications with Connecticut regulators by the third quarter of 2009 with construction beginning as early as late 2010.  We currently expectthat the project towill be placed in service as early as 2012.in late 2015.  

The third parttiming of NEEWS is the Central Connecticut Reliability Project which involves construction of a new line from Bloomfield, Connecticutis expected to Watertown, Connecticut.  This line would provide us with another 345 KV connection to move power across the state of Connecticut.  The timing of this project would be six to twelve months behind the other two projects,Interstate Reliability Project and CL&P currently expectscost approximately $338 million.  ISO-NE continues to fileassess the siting application in early 2010 with construction beginning in 2011.  The project is currently expected to be placed in service in 2013 at a cost of approximately $315 million.  need date for the Central Connecticut Reliability Project and we expect that ISO-NE will conclude its evaluation by mid-2011.

Included as part of NEEWS are approximately $210$84 million of expenditures for associated reliability related expenditures, someprojects, all of which may be incurredhave received siting approval and most are under construction.  The in-service dates for these projects range from later this year through 2013.

Northern Pass Transmission Line Project

NPT is a limited liability company jointly formed by NU and NSTAR to construct, own and operate the Northern Pass transmission line, a new HVDC transmission line from the border of Canada and the United States to Franklin, New Hampshire that will interconnect at the border with a new HVDC transmission line being developed by HQ TransEnergie, the transmission subsidiary of HQ.  NUTV, a subsidiary of NU, holds a 75 percent interest in advanceNPT, with NSTAR Transmission Ventures, Inc., a subsidiary of NSTAR, holding the remaining 25 percent.  Consistent with FERC's February 11, 2011 order accepting the TSA between NPT and Hydro Renewable Energy that was filed December 15, 2011, NPT will charge Hydro Renewable Energy cost-based rates for firm transmission service over the Northern Pass line for a 40-year term.  The projected cost-of-service calculation includes an ROE of 12.56 percent through the construction phase of the three major projects.project.  Upon commercial operation, the ROE will be equal to the ISO-NE regional rates base ROE (currently 11.14 percent) plus 1.42 percent based on a deemed capital structure for NPT of 50 percent debt and 50 percent equity.  

DuringIn October 2010, NPT filed the Northern Pass project design with ISO-NE for technical approval and filed a presidential permit application with the DOE.  The DOE application seeks permission for NPT to construct and maintain facilities that cross the U.S. border and connect to HQ TransEnergie's facilities in Canada.  Assuming timely regulatory review and siting approvals, NPT expects to commence construction of the Northern Pass in 2013, with power flowing across the line in late 2015.  

We currently estimate that our 75 percent share of the costs to build the Northern Pass transmission project will be approximately $830 million out of total expected costs of approximately $1.1 billion (including capitalized AFUDC).

Other Transmission Transactions

In July 2010, CL&P and UI entered into an agreement under which UI would acquire certain transmission assets within CL&P's portion of each of the NEEWS segments.  Under the terms of the agreement, which has received approval process, state regulators may require changes in configurationfrom the FERC and the DPUC, UI will have the option to address local concerns that could increase construction costs.  Our current designinvest up to $69 million or an amount equal to 8.4 percent of CL&P's costs for NEEWS does not contemplate any underground lines. Building any transmission lines underground, particularly 345KV lines, would increase total costs, and our estimate could be increased during the siting approval process.assets, which are expected to aggregate approximately $828 million.

On December 12, 2008, we submitted jointly with NSTAR,17, 2010, CL&P and CTMEEC, a petition with the FERC requesting a declaratory order that would allow us and NSTAR to enternon-profit municipal joint action transmission entity formed by several Connecticut municipal electric companies, entered into a bilateral transmission services agreement with H.Q. Energy Services (U.S.) Inc. (HQUS), a wholly-owned subsidiary of Hydro-Québec.  Under such an agreement NU, subject to DPUC approval, under which CTMEEC would acquire a segment of CL&P’s high voltage transmission lines in the town of Wallingford, Connecticut.  The transaction was approved by FERC on January 31, 2011.  The purchase price will be based on the net book value of the assets at the time of the closing of the sale in May 2011, projected to be approximately $42.3 million.  CL&P will continue to operate and NSTAR subsidiaries would sell to HQUS 1,200 megawatts of firm electric transmission service over a new, participant-funded transmission tie line connecting New England withmaintain the Hydro-Québec system in orderlines for HQUS to sell and deliver this same amount of firm electric power from Canadian low-carbon energy resources to New England.CTMEEC.  

If FERC issues the declaratory order as we anticipate, NU and NSTAR would subsequently seek approval from FERC of the specific terms and conditions of the transmission arrangement and approvals from state regulators of the terms and conditions of the power purchase arrangements.  NU, NSTAR and HQUS have signed memoranda of understanding to develop this transmission project on an exclusive basis.  This project would provide a competitive source of low-carbon power that is favorable in comparison to current alternatives.  It also would provide for an expansion of New England’s transmission system without raising regional transmission rates.

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NU, NSTAR and HQUS have also begun discussions on the specifics of a potential long-term power purchase agreement that would ensure the line is utilized to bring low-carbon power to benefit New England customers.  A FERC order is expected in the first half of 2009, and if the order approves the proposal, then NU and NSTAR plan to negotiate a power purchase agreement with HQUS later in 2009.  The terms of such an agreement would be subject to regulatory approval in several states.

Assuming completion of an acceptable power purchase agreement, and receipt of all necessary state and federal regulatory approvals, we expect this project to be under construction between 2011 and 2014.  Our initial estimate of our portion of the construction funding is approximately $525 million.  HQUS will reimburse NU and NSTAR for the total costs of this project, including an investment return to these companies, over the estimated 40-year operating life of the transmission line.  NU and NSTAR’s intent is to create an agreement that approximates a typical FERC approved cost-of-service rate structure.  The revenue recovery model will ultimately require FERC approval.

Transmission Rate Base

Under our FERC-approved tariff, transmission projects generally enter rate base once they are placed in commercial operation.  Additionally,However, 100 percent of the NEEWS projects will enter rate base during their construction period.  At the end of 2008,2010, our transmission rate base was approximately $2.4$2.8 billion, including approximately $2.0$2.1 billion at CL&P, $250$341 million at PSNH and $80$269 million at WMECO.  We forecast that our total transmission rate base will grow to approximately $5.0$4.8 billion by the end of 2013.  This increase in transmission rate base is driven by the need to improve the capacity and reliability of our regulated transmission system.

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A summary of projected year-end transmission rate base by regulated company is as follows (millions of dollars):

The projected rate base amounts reflected above assume that $1.49 billion in transmission projects associated with NEEWS will be completed before the end of 2013 and the transmission line connecting to HQUS is built.  Numerous factors, some of which are beyond our control, may impact the rate base amounts above,2015, including the level and timing of capital expenditures and plant placed in service and regulatory approvals.  For more information regarding Regulated Transmission matters, see "Transmission Rate Matters and FERC Regulatory Issues" and "Business Development and Capital Expenditures" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in this Annual Report on Form 10-K.

approximately $830 million at NPT.   

CONSTRUCTION AND CAPITAL IMPROVEMENT PROGRAM

The principal focus of our construction and capital improvement program is maintaining, upgrading and expanding theour existing electric generation, transmission and distribution systemsystems and our natural gas distribution system.  Our consolidated capital expenditures in 2008, including amounts incurred but not paid, cost of removal, allowance for funds used during construction and the capitalized portions of pension and PBOP expense or income (all of which are non-cash factors in determining rate base),2010 totaled approximately $1.3$1 billion, almost all of which ($967 million) was expended by the regulatedRegulated companies.  The capital expenditures of these companies in 20092011 are estimated to total approximately $851 million.  Of this amount, approximately $375$1.2 billion, $477 million is expected to be expended by CL&P, $310$284 million by PSNH, $100$287 million by WMECO and $66$113 million by Yankee Gas.  This capital budget includes anticipated costs for all committed capital projects (i.e .,(i.e., generation, transmission, distribution, environmental compliance and others) and those reasonably expectedwe expect to become committed projects in 2009.  We expect to evaluate needs beyond 2009 in light of future developments, such as restructuring, industry consolidation, performance and other events.  Increases in proposed distribution capital expenditures stems primarily from increasing labor and material costs and an aging infrastructure.  The costs (both labor and material) that our regulated companies incur to construct and maintain their electric delivery systems have increased dramatically in recent years.  These increases have been driven primarily by higher demand for commodities and electrical products, as well as increased demand for skilled labor.  Our regulated companies have many major classes of equipment that are approaching or beyond their useful lives, such as old and obsolete distribution poles, underground primary cables and substation switchgear. Replacement of this equipment is extremely costly.2011.  

In 2010, CL&P’s transmission capital expenditures in 2008 totaled approximately $586 million.  The decrease in transmission segment$107 million, and its distribution capital expenditures in 2008 as compared with 2007 was primarily due to the early completion of the major southwest Connecticut transmission projects discussed above.totaled approximately $305 million.  For 2009,2011, CL&P projects transmission capital expenditures of approximately $97$137 million and distribution capital expenditures of approximately $337 million.  During the period 20092011 through 2013,2015, CL&P plans to invest approximately $974 million$1 billion in transmission projects, the majority of which will be for NEEWS.

In addition to its transmission projects, CL&P plans distribution capital expenditures to meet growth requirementsNEEWS and improve the reliability of its distribution system.  In 2008, CL&P's distribution capital expenditures totaled approximately $297 million.  CL&P projects its distribution capital expenditures in 2009 to be approximately $278 million.  CL&P plans to spend approximately $1.59 billion$1.9 billon on distribution projects during the period 2009-2013.projects.  If all of the distribution and transmission projects are built as proposed, CL&P’s rate base for electric transmission is projected to increase from approximately $2.0$2.1 billion at the end of 20082010 to approximately $2.5$2.6 billion by the end of 2013,2015, and its rate base for distribution assets is projected to increase from approximately $2.0$2.3 billion to approximately $3.0$3.3 billion over the same period.pe riod.

In 2008,2010, PSNH's transmission capital expenditures totaled approximately $82$49 million, its distribution capital expenditures totaled $98approximately $84 million and its generation capital expenditures totaled $74$177 million.  For 2009,2011, PSNH projects transmission capital expenditures of approximately $58$59 million, distribution capital expenditures of approximately $96$113 million and generation capital expenditures of approximately $156$112 million.  The increase inbulk of the generation capital expenditures is mostly due to the expenditures for the Merrimack Clean Air project.Project.  During the period 2009-2013,2011 through 2015, PSNH plans to spend approximately $1.1 billion$293 million on transmission projects, approximately $559$621 million on distribution projects, and $623$274 million on generation projects.  If all of the distribution, generation and transmission projects are built as proposed, PSNH’s rate base for electric transmission is projected to increase from approximately $250 mil lion$341 million at the enden d of 20082010 to approximately $1.2 billion$540 million by the end of 2013,2015, and its rate base for distribution and generation assets is projected to increase from approximately $1.0$1.2 billion to approximately $2.0$1.9 billion over the same period.

In 2008,2010, WMECO's transmission capital expenditures totaled approximately $44.2$95 million, and its distribution capital expenditures totaled approximately $37.8$33.1 million and solar generation expenditures were $10 million.  In 2009,2011, WMECO projects transmission capital expenditures of approximately $70$229 million, and distribution capital expenditures of approximately $30 million.$36 million and $22 million on solar generation.  During the period 2009-2013,2011 through 2015, WMECO plans to spend approximately $888$732 million on transmission projects, with the bulk of that amount to be spent on the NEEWS Greater Springfield Reliability Project, andGSRP, approximately $168$194 million on distribution projects.projects and $46 million on solar generation.  If all of the generation, distribution and transmission projects are built as proposed, WMECO’s rate base for electric transmission is projected to increase from approximately $269 million at the end of 2010 to approximately $876$803 million by the end of 20132015 and its rate base forfo r distribution and generation assets is projected to increase from approximately $374$423 million to approximately $497$488 million over the same period.

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In 2008,2010, Yankee Gas’sGas capital expenditures totaled approximately $44$95 million.  For 2009,2011, Yankee Gas projects total capital expenditures of approximately $66 million.$113 million, approximately $30 million of which is expected to be related to the WWL project, $37 million related to basic business activities such as relocation of conflicting gas facilities and the purchase of meters, tools and information technology; $30 million related to reliability improvements; and $16 million for load growth and new business requests.  During the period 2009-2013,2011 through 2015, Yankee Gas plans on making approximately $399$587 million of capital expenditures.expenditures, including approximately $30 million on the WWL project.  Future capital spending will likely be affected by price differences between the cost of natural gas with respect to home heating oil, natural gas supply, new home construction, road reconstruction, regulatory mandates and business requirements. &n bsp;Excluding non-recurring major projects, NU expects that approximately 28 percent of Yankee Gas’ capital expenditures over the 2011-2015 period to be related to basic business activities, approximately 28 percent related to load growth and new business, and approximately 39 percent related to reliability initiatives, with the balance related to the WWL project.  If all of Yankee Gas’sGas projects are built as proposed, Yankee Gas’sGas’ investment in its regulated assets is projected to increase from approximately $685$682 million at the end of 20082010 to approximately $890$969 million by the end of 2013.2015.

For more information regarding NU and its subsidiaries' construction and capital improvement programs, see "Business Development and Capital Expenditures" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in this Annual Report on Form 10-K.

STATUS OF EXIT FROM COMPETITIVE ENERGY BUSINESSES

Since 2005, we have been in the process of exiting our competitive energy businesses and are now focusing exclusively on our regulated businesses.  At December 31, 2008, our competitive businesses consisted solely of (i) Select Energy’s few remaining wholesale marketing contracts and NGS and its affiliates, which are winding down, and (ii) Boulos, NU Enterprises’ remaining active energy services business.

On May 31, 2008, Select Energy’s remaining wholesale sales contract in the PJM power pool expired.  Select Energy’s wholesale contract with The New York Municipal Power Agency (NYMPA) and related supply contracts expire in 2013.  In addition to the PJM and NYMPA contracts, Select Energy's only other long-term wholesale obligation is a non-derivative contract to operate and purchase the output of a certain generating facility in New England through 2012.

For more information regarding the exit of the competitive businesses, see "NU Enterprises Divestitures" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 15, "Restructuring and Impairment Charges and Discontinued Operations," to the consolidated financial statements, contained within this Annual Report on Form 10-K.

FINANCING

We paid dividends on our common shares totaling $129.1NU subsidiaries issued a total of $145 million in 2008, compared to $121long-term debt in 2010.  On March 8, 2010, WMECO issued $95 million in 2007, reflecting increases in the quarterly dividend amount that were effective in the third quarters of 2007 and 2008.  On February 10, 2009, the NU Board of Trustees declaredsenior unsecured notes due March 1, 2020 carrying a quarterly dividend of $0.2375 per share, payable on March 31, 2009, an increase of $0.10 per share above the previous annualizedcoupon rate of $0.85 per share.  This dividend reflects the company’s policy, announced in November 2008,5.1 percent and on April 22, 2010, Yankee Gas issued $50 million of targetingfirst mortgage bonds through a dividend payout ratio of approximately 50 percent of earnings,private placement with a goalmaturity date of continuing the policyApril 1, 2020 carrying a coupon rate of increasing the dividend at a rate above industry average and providing an attractive return to shareholders.  NU expects to revisit its dividend levels in the first quarter of each year.4.87 percent.

In general,addition, on April 1, 2010, CL&P completed the regulated companies pay approximately 60remarketing of $62 million of tax-exempt secured PCRBs.  The PCRBs carry a coupon rate of 1.4 percent of their cash earningsuntil April 1, 2011, at which time CL&P expects to remarket the bonds.  

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On September 24, 2010, NU parent in the form of common dividends.  In 2008,entered into a three-year $500 million unsecured revolving credit facility, and CL&P, PSNH, WMECO, and Yankee Gas paid $106.5jointly entered into a three-year $400 million $36.4 million, $39.7 million,unsecured revolving credit facility, both replacing five-year credit facilities on similar terms and $31 million, respectively, in common dividendsconditions that were scheduled to NU parent.  In 2008,expire on November 6, 2010.  Like the previous facility, NU’s new revolving credit facility allows NU parent contributed $210to borrow on a short-term or long-term basis, or issue LOCs, up to $500 million of equityin the aggregate.  Under their new revolving credit facility, CL&P and PSNH are each able to CL&P, $75.6draw up to $300 million, to PSNH, $16.3 million towith WMECO and $20.8Yankee Gas each able to draw up to $200 million, all subject to Yankee Gas.  the $400 million maximum aggregate borrowing limit.

Our credit facilities and indentures require that NU parent’s ability to pay common dividends is subject to approval by the Board of Trusteesparent and to NU’s future earnings and cash flow requirements.  It is not regulated under the Federal Power Act, but may be limited by certain state statutes, the leverage restrictions tied to its required ratio of consolidated total debt to total capitalization in its revolving credit agreement, and the ability of its subsidiaries, to pay common dividends.  The Federal Power Act does, however, limit the payment of dividends by CL&P, PSNH and WMECO to their respective retained earnings balances unless a higher amount is approved by FERC, and PSNH is required to reserve an additional amount under its FERC hydroelectric license conditions.  In addition, certain state statutes may impose additional limitations on the regulated companies.including CL&P, PSNH, WMECO and Yankee Gas, alsocomply with certain financial and non-financial covenants as are parties to a revolving credit agreement that imposes leverage restrictions.

Our total debt,customarily included in such agreements, including short-term debt, capitalized lease obligations and prior spent nuclear fuel liabilities, but not including RRBs, was approximately $4.8 billion as of December 31, 2008.

During 2008, the NU companies issued an aggregate of $760 million of long-term debt, as follows:  On May 27, 2008, CL&P issued $300 million of 10-year first and refunding mortgage bonds carrying a coupon rate of 5.65 percent, and PSNH issued $110 million of 10-year first mortgage bonds with a coupon rate of 6.00 percent.  On June 5, 2008, NU parent issued $250 million of five-year senior unsecured notes with a coupon rate of 5.65 percent, and on October 7, 2008, Yankee Gas issued $100 million of 10-year first mortgage bonds at 6.9 percent.  In addition, on February 13, 2009, CL&P issued $250 million of 10-year first mortgage bonds at 5.5 percent.

NU parent has a combined credit line and letter of credit (LOC) facility in a nominal aggregate amount of $500 million, including the lending commitment of Lehman Brothers Commercial Bank, Inc. (LBCB) (as discussed below), which expires on November 6, 2010. At December 31, 2008, NU parent had $304 million of borrowings and $87 million of LOCs issued for the benefit of certain subsidiaries outstanding under that facility.  NU parent had approximately $50 million of borrowing availability on this facility as of February 25, 2009, excluding the remaining unfunded commitment of LBCB.  NU also had approximately $466 million of externally invested cash at February 25, 2009.

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The regulated companies maintain a joint credit facility in a nominal aggregate amount of $400 million, including the lending commitment of LBCB, which also expires on November 6, 2010.  There were $315 million of short-term borrowings outstanding under that facility at December 31, 2008.  We had approximately $1 million of borrowing availability on this facility as of February 25, 2009, excluding the remaining unfunded commitment of LBCB.  NU also had approximately $466 million of externally invested cash at February 25, 2009.

The lenders under these facilities are:  Bank of America, N.A.; Barclays Bank PLC; BNY Mellon, N.A.; Citigroup Inc.; HSBC Bank USA, N.A.; JPMorgan Chase Bank, N.A.; LBCB; Sumitomo Mitsui Banking Corporation (Sumitomo); Toronto Dominion (Texas) LLC; Union Bank of California, N.A.; Wachovia Bank, N.A.; and Wells Fargo Bank, N.A.  Lehman Brothers Holdings Inc., the parent of LBCB, filed for Chapter 11 bankruptcy protection in September 2008.  LBCB's original aggregate lending commitment under the two facilities was $85 million, of which $30 million was assigned to Sumitomo in late September 2008.  At December 31, 2008, LBCB had advanced approximately $19.2 million under the facilities and had declined to fund the remainder of its commitment.  As a result, when current loans from LBCB are repaid, we will be limited to an aggregate of $845 million of borrowing capacity under our credit facilities, which we believe will provide sufficient operating flexibility to maintain adequate amounts of liquidity.

PSNH has outstanding approximately $407 million of PCRBs, one series of which, in the aggregate principal amount of $89.3 million, bears interest at a rate that is periodically set pursuant to auctions.  Since March 2008, a significant majority of this series of PCRBs has been held by remarketing agents as the result of failed auctions due to general market concerns.  The interest rate on these PCRBs has reset by formula under the applicable documents every 35 days and has been between 0.2 percent and 4 percent since March 2008.  The formula is based on a combination of the ratings on the PCRBs and an index rate, which provides for a current interest rate of 0.3 percent.  We are not obligated to purchase these PCRBs, which mature in 2021, from the remarketing agents.

In addition, CL&P has approximately $423.9 million of PCRBs, one series of which, in the aggregate principal amount of $62 million, had a fixed interest rate for a five-year period that expired on September 30, 2008.  CL&P chose to acquire these PCRBs on October 1, 2008 as a result of poor liquidity in the tax-exempt market.  These PCRBs, which mature in 2031, have not been retired, and CL&P expects to remarket them when conditions in the market improve.

Under their revolving credit facility agreements, each of NU, CL&P, WMECO, PSNH and Yankee Gas must maintainmaintaining a ratio of consolidated debt to total capitalization of no more than 65 percent.  At December 31, 2008, NU, CL&P, WMECO, PSNH,All such companies currently are, and Yankee Gas were, and are expectedexpect to remain in compliance with this ratio.these covenants.    

For more information regardingWe have annual sinking fund requirements of $4.3 million continuing in 2011 through 2012, the mandatory tender of $62 million of tax-exempt PCRBs by CL&P on April 1, 2011, at which time CL&P expects to remarket the bonds in the ordinary course.  Neither NU andnor any of its subsidiaries' financing, see "Note 2, "Short-Term Debt," and Note 11, "Long-Term Debt," to the Consolidated Financial Statements and "Liquidity" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this Annual Report on Form 10-K.subsidiaries have any debt maturities until April 1, 2012.  

In light of the 2010 Tax Act and the related cash flow benefits, we are currently reevaluating the timing of our previously planned NU common equity issuance.  If we complete the proposed merger with NSTAR, we would no longer need to undertake the previously planned $300 million NU common equity issuance in 2012 nor issue any additional equity in the foreseeable future.  

NUCLEAR DECOMMISSIONING

GeneralGeneral

CL&P, PSNH, WMECO and several other New England electric utilities are the stockholders ofin three inactive regional nuclear generation companies, Connecticut Yankee Atomic Power Company (CYAPC), Maine Yankee Atomic Power Company (MYAPC)CYAPC, MYAPC and Yankee Atomic Electric Company (YAEC) (theYAEC (collectively, the Yankee Companies).  The Yankee Companies have completed the physical decommissioning of their respective generation facilities and are now engaged in the long-term storage of their spent nuclear fuel.  Each Yankee Company collects decommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, PSNH and WMECO.WMECO and several other New England utilities.  These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates.  The ownership percentages of CL&P, PSNH and WMECO in the Yankee Companies are set forth below:

Our share of the obligations to support the Yankee Companies under FERC-approved rulescontracts is the same as the ownership percentages above.

For more information regarding decommissioning and nuclear assets, see "Deferred Contractual Obligations" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in this Annual Report on Form 10-K.

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OTHER REGULATORY AND ENVIRONMENTAL MATTERS

General

We are regulated in virtually all aspects of our business by various federal and state agencies, including the FERC, the SEC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each of our companies operates, including the DPUC, havingwhich has jurisdiction over CL&P and Yankee Gas, the NHPUC, havingwhich has jurisdiction over PSNH, and the DPU, havingwhich has jurisdiction over WMECO.

Environmental Regulation

We are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters.  Additionally, our major generation and transmission facilities may not be constructed or significantly modified without a review of the environmental impact of the proposed construction or modification by the applicable federal or state agencies.  PSNH owns approximately 1,200 MW of generation assets and plansexpects to spend approximately $457$430 million to installon its Clean Air Project, the installation of a wet flue gas desulphurization system at its Merrimack Stationcoal station to reduce its mercury emissions of its coal fired plants in compliance with current New Hampshire law.and sulfur dioxide emissions.  Compliance with additional increasingly stringent environmental laws and regulations, particularly air and water pollution control requirements may limitcause changes in operations or require further substantial investments in new equipment at existing facilities.

Water Quality Requirements

The federal Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES)NPDES permit from the United States Environmental Protection AgencyEPA or state environmental agency specifying the allowable quantity and characteristics of its effluent.  States may also require additional permits for discharges into state waters.  We are in the process of obtaining or renewing all required NPDES or state discharge permits in effect for our facilities.  ComplianceIn each of the last three years, the costs incurred by the Company related to compliance with NPDES and state discharge permits has necessitated substantial expenditures and may require further significant expenditures, which are difficulthave not been material.  The Company expects to estimate, becauseincur additional costs related to these permits in the future; however, due to uncertainty regarding the imposition of new or additional requirements, or restrictions that could be imposed in the future.Company is unable to accurately estimate such costs.

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Air Quality Requirements

The Clean Air Act Amendments of 1990 (CAAA),CAAA, as well as state laws in Connecticut, Massachusetts and New Hampshire law, impose stringent requirements on emissions of SO2SO₂ and nitrogen oxides (NOX)NO_X for the purpose of controlling acid rain and ground level ozone.  In addition, the CAAA address the control of toxic air pollutants.  Installation of continuous emissions monitors and expanded permitting provisions also are included.

In New Hampshire, the Multiple Pollutant Reduction Program capped NOX, SO2 NO_X, SO₂and carbon dioxide (CO2)CO₂ emissions for current compliance beginning in 2007.  In addition, a 2006 New Hampshire law requires PSNH to install a wet flue gas desulphurization system, known as "scrubber" technology, to reduce mercury emissions of its coal fired plants by at least 80 percent (with the co-benefit of reductions in SO2SO₂ emissions as well).  Wet scrubber technology will be installed at Merrimack Station in Bow, New Hampshire. PSNH currently anticipates that compliance withThe Clean Air Project addresses this law will cost approximately $457 million.requirement.  PSNH began site work for this project in November 2008.  The project2008 and is scheduled to be completedcomplete it by the end of 2012.mid-2012.

In addition, Connecticut, New Hampshire and Massachusetts are each members of the Regional Greenhouse Gas Initiative (RGGI).  RGGI, is a cooperative effort by ten northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO2CO₂ emissions from fossil fuel-fired electric generating plants.  It is the first market-based, mandatory cap-and-trade program in the U.S. designed to reduce greenhouse gas emissions.  Each of the participating states has regulations in place to cap and then reduce the amount of CO2 that power plants in their region are allowed to emit. Power sector CO2 emissions are capped at current levels through 2014.  The cap will then be reduced by 2.5 percent in each of the four years 2015 through 2018, for a total reduction of 10 percent.  RGGI is composed of individual CO2 budget trading programs in each of the participating states. Each participating state’s CO2 budget trading program establishes its respective share of the regional cap, and each state will issue CO2 allowances in a number equivalent to its portion of the regional cap.  Each CO2 allowance represents a permit to emit one ton of CO2 in a specific year.  The RGGI states will distribute CO2 allowances primarily through regional auctions.

Because CO2CO₂ allowances issued by any participating state will be usable across all ten RGGI state programs, the ten individual state CO2 budgetCO₂ trading programs, in the aggregate, will form one regional compliance market for CO2CO₂ emissions.  Initial CO2 allowance auctions were held in 2008 as pre-compliance events to facilitate market price discovery and compliance planning by regulated CO2 emitters.  A regulated power plant must hold CO2CO₂ allowances equal to its emissions to demonstrate compliance at the end of a three-year compliance period beginningthat began in 2009.

Connecticut adopted regulations in connection with RGGI in July 2008 which established an auction clearing price threshold of $5 per CO2 allowance, above which all auction proceeds will be rebated to customers.  For proceeds up to the clearing price threshold, 69.5 percent will be directed to the conservation and load management programs managed by the state’s utilities in conjunction with the Energy Conservation Management Board.  Seventy-five percent of the RGGI auction proceeds directed to conservation and load management programs will be allocated to CL&P’s programs.  Because neither CL&P does notnor WMECO currently own any generating assets it(other than the solar facilities owned by WMECO, which do not emit CO₂), neither is not required to acquire CO2CO₂ allowances; however, the CO₂allowance costs borne by generators that provide energy supply to CL&P and WMECO will likely be included in wholesale rates charged to CL&P in standard offer type contracts.

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Massachusetts law does not set an auction clearing price threshold for RGGI auctions.  The law requires 80 percent of RGGI auction proceeds to be allocated to utility energy efficiency and demand response programs.  Because WMECO does not own any generation assets, it is not required to acquire any CO2 allowances; however, thethem, which costs will likely be included in wholesale rates charged to WMECO in standard offer type contracts.

New Hampshire law sets an auction clearing price threshold of $6 per CO2 allowance in 2009, above which all auction proceeds will be rebated toare then recoverable from customers.  Proceeds below the threshold are to be used for demand response and energy efficiency programs.

PSNH anticipates that its generating units will emit between 4four million and 5five million tons of CO2CO₂ per year after taking into effect the operation of PSNH’s Northern Woods wood-burning generating plant that, underWood Power Project.  Under the RGGI formula, this Project decreased PSNH’s responsibility for reducing fossil-fired CO2CO₂ emissions by approximately 425,000 tons per year, or almost ten percent.  New Hampshire legislation provides up to 2.5 million banked CO2CO₂ allowances per year for PSNH’s fossil fueled generating plants during the 2009-20112009 through 2011 compliance period.  These banked CO2CO₂ allowances will initially comprise approximately one-half of the yearly CO2CO₂ allowances required for PSNH’s generating plants to comply with RGGI and suchRGGI.  Such banked allowances will decrease over time.  PSNH expects to satisfy its remaining RGGI requirements by purchasing CO2CO₂ allowances at auction or in the secondary market.  The cost of complying with RGGI req uirementsrequirements is recoverable from PSNH customers.

The first regional auction of RGGI CO2 allowances took place on September 25, 2008.  Six states offered allowances for sale.  At the auction, more than 12.5 million CO2 allowances were sold at the clearing price of $3.07 per CO2 allowance.  The auction raised $38.6 million for use by the six RGGI states.  The next regional auction took place on December 17, 2008.  All ten RGGI states participated and more than 31.5 million CO2 allowances were sold at a clearing price of $3.38 per allowance.  The auction raised $106.5 million for use by the ten RGGI states.  For 2009, four quarterly regional auctions are scheduled for March, June, September and December.

Each of the states in which we do business also has renewable portfolio standards (RPS).  New Hampshire’s renewable portfolio standards provision requires increasingRPS requirements, which generally require fixed percentages of the electricity soldenergy supply to retail customers in the state, beginning in 2008, to have direct ties to renewable sources, ultimately reaching 23.8 percent by 2025. PSNH is required to comply with these standards.  We expect that the additional costs incurred to meet this new requirement will be recovered through PSNH’s energy service rates.  Connecticut's RPS statutes require that a specific percentage of the generation provided to Connecticut consumers be producedcome from renewable energy sources such as solar, hydropower, landfill gas, fuel cells and other similar sources.  Beginning

New Hampshire’s RPS provision requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources, beginning in 2008 at four percent and ultimately reaching 23.8 percent by 2025.  In 2010, the total RPS obligation was 7.5 percent of total generation supplied to customers.  Energy suppliers, like PSNH, purchase RECs from producers that generate energy from a qualifying resource and use them to satisfy the RPS requirements.  PSNH also owns renewable sources and uses both internally generated RECs and purchased RECs to meet its RPS obligations.  To the extent that PSNH is unable to purchase sufficient RECs, it makes up the difference between the RECs purchased and its total obligation by making an alternative compliance payment for each REC requirement for which PSNH is deficient.  The costs of both the RECs and alternative compliance payments do not impact earni ngs, as these costs are recovered by PSNH through its ES rates charged to customers.

Connecticut's RPS statute requires electricity suppliers to meet renewable energy standards, beginning with a 4four percent requirementRPS in 2004, the requirement2004. This percentage increases each year.  For 2009,2010, the requirement is 12 percent, increasing to&nbs p;was 14 percent by 2010,with goals of 19.5 percent by 2015 and 27 percent by 2020.  CL&P is permitted to pass any costs incurred in complying with RPS on to customers through rates.

Massachusetts’ RPS program required electricity suppliers to meet a 1one percent renewable energy standard in 2003 which increased to 4 percent for 2009 and has a goal of 15 percent by 2015.  For 2010, the requirement was five percent.  WMECO is permitted to pass any costs incurred in complying with RPS on to customers through rates.

In addition, many states and environmental groups have challenged certain of the federal laws and regulations relating to air emissions as not being sufficiently strict.  As a result, it is possible that state and federal regulations could be developed that will impose more stringent limitations on emissions than are currently in effect.

Hazardous Materials Regulations

Prior to the last quarter of the 20th20^th century when environmental best practices and laws were implemented, utility companies often disposed of residues from operations were often disposed of by depositing or burying such materialsthem on-site or disposing of them at off-site landfills or other facilities.  Typical materials disposed of include coal gasification waste,byproducts, fuel oils, ash, gasoline and other hazardous materials that might contain polychlorinated biphenyls.biphenyls or that otherwise might be hazardous.  It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks.  We have recorded a liability for what we believe is, based upon currently available information, our estimated environmental investigation and/or remediation costs for waste disposal sites for which we expect to bear legal liability, andliability.  We continue to evaluate the environmental impact of our formerfor mer disposal practices.  Under federal an dand state law, government agencies and private parties can attempt to impose liability on us for such past disposal.these

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practices.  At December 31, 2008,2010, the liability recorded by us for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $27.4$37.1 million, representing 54 liabilities. All cost estimates were made in accordance with generally accepted accounting principles where investigation and/or remediation costs are probable and reasonably estimable.58 sites.  These costs could be significantly higher if additional remedial actions becomeremediation becomes necessary or when additional information as to the extent of contamination becomes available.

The most significant liabilities currently relate to future clean up costs at former manufactured gas plant (MGP)MGP facilities.  These facilities were owned and operated by our predecessor companies to us from the mid-1800's to mid-1900's.  By-products from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose risks to human health and the environment.  We, through our subsidiaries, currently have partial or full ownership responsibilities at 28 former MGP sites.  Of our total recorded liabilities of $27.4 million, a reserve of approximately $25.4 million has been established to address future investigation and/or remediation costs at MGP sites.  In addition, Holyoke Water Power Company (HWP),

HWP, a wholly-owned subsidiary of NU, is continuing to evaluate additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with aan MGP which itsite that HWP sold to Holyoke Gas and Electric (HG&E),HG&E, a municipal electric utility, in 1902.  HWP and HG&E share responsibilityis at least partially responsible for the site. HWPthis site and has already conducted substantial investigative and remediation activities.

The Massachusetts Department of Environmental Protection (MA DEP) issued a letter on April 3, 2008 to HWP and HG&E, providing conditional authorization for additional investigatory and risk characterization activities and providing detailed comments on HWP’s 2007 reports and proposals for further investigations.  MA DEP also indicated that further removal of tar in certain areas was necessary prior to commencing many of the additional studies and evaluation.  HWP has developed and begun to implement plans for

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additional investigations in conformity with MA DEP’s guidance letter, including estimated costs and schedules.  These matters are subject to ongoing discussions with MA DEP and HG&E and may change from time to time.

There are many outcomes that could affect our estimates and require an increase to the reserve, or range of costs, and a reserve increase would be reflected as a charge to pre-tax earnings.  However, we cannot reasonably estimate the range of additional investigation and remediation costs because they will depend on, among other things, the level and extent of the remaining tar that may be required to be remediated, the extent of HWP’s responsibility and the related scope and timing, all of which are difficult to estimate because of a number of uncertainties at this time.  Further developments may require a material increase to this reserve.

HWP's share of the remediation costs related to this site is not recoverable from customers.

For further information on environmental liabilities, see Note 7B, "Commitments and Contingencies - Environmental Matters" to the Consolidated Financial Statements contained in this Annual Report on Form 10-K.

Electric and Magnetic Fields

For more than twenty years, published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF)EMF associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes.  Although weak health risk associations reported in some epidemiology studies remain unexplained, most researchers, as well as numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, have concluded that the available body of scientific information does not support the conclusion that EMF affects human health.

We have closely monitored research and government policy developments for many years and will continue to do so.  In accordance with recommendations of various regulatory bodies and public health organizations, we reduce EMF associated with new transmission lines by the use of designs that can be implemented without additional cost or at a modest cost.  We do not believe that other capital expenditures are appropriate to minimize unsubstantiated risks.

Global Climate Change and Greenhouse Gas Emission Issues

Global climate change and greenhouse gas emission issues have received an increased focus from state governments and the federal government, particularly in recent years.  The EPA has initiated a rulemaking addressing greenhouse gas emissions and, on December 7, 2009, issued a finding that concluded that greenhouse gas emissions are "air pollution" and endanger public health and welfare and should be regulated.  The largest source of greenhouse gas emissions in the U.S. is the electricity generating sector.  The EPA has mandated GHG emission reporting beginning in 2012 for 2011 emissions for certain aspects of our business including stationary combustion, volume of gas supplied to large customers and fugitive emissions of SF-6 gas and methane.

We are continually evaluating the risks presented by climate change concerns and issues.  Such concerns could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the generating facilities we own and operate as well as general utility operations.  (See "Air Quality Requirements" in this section for information concerning RGGI)  These could include federal "cap and trade" laws, or regulations requiring additional capital expenditures at our generating facilities.  In addition, such rules or regulations could potentially impact the prices we pay for goods and services provided by companies directly affected by such rules or regulations.  We would expect that any costs of these rules and regulations would be recovered from customers, but such costs could impact energy use by our customers.  

Global climate change could potentially impact weather patterns such as increasing the frequency and severity of storms or altering temperatures.  These changes could affect our facilities and infrastructure and could also impact energy usage by our customers.  

FERC Hydroelectric Project Licensing

New Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC.  Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, or (ii) the United States may take over the project or (iii) the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.

PSNH owns nine hydroelectric generating stations with an aggregate of approximately 66.3 MW of capacity, with a current claimed capability representing winter rates of approximately 69.5 MW.  Of these nine plants,71 MW, eight of which are licensed by the FERC under long-term licenses that expire on varying dates from 20092017 through 2036.  As a licensee under the Federal Power Act (FPA),2047.  PSNH and its licensed hydroelectric projects are subject to conditions set forth in such licenses, the FPAFederal Power Act and related FERC regulations, including provisions related to the condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment and severance damages and other matters.

FERC hydroelectric project licenses expire periodically, and the generating facilities must be relicensed at such times.  A new FERC license for PSNH’s Merrimack River Hydroelectric Project, which consists of the Amoskeag, Hooksett and Garvins Falls generating stations, was issued on May 18, 2007.  PSNH's Canaan Hydroelectric Project is currently undergoing relicensing proceedings.  On January 16, 2009, FERC issued a new license for this project.  The new license takes effect upon the July 3, 2009 expiration of its current license.  The water quality certification associated with this new license has been appealed to the Vermont Environmental Court.

Licensed operating hydroelectric projects are not generally subject to decommissioning during the license term in the absence of a specific license provision whichthat expressly permits the FERC to order decommissioning during the license term.  However, the FERC has taken the position that under appropriate circumstances it may order decommissioning of hydroelectric projects at relicensing or may require the establishment of decommissioning trust funds as a condition of relicensing.  The FERC may also require project

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decommissioning during a license term if a hydroelectric project is abandoned, the project license is surrendered or the license is revoked.   PSNH is not presently encountering any of these challenges.

At this time, it appears unlikely that the FERC will order decommissioning of PSNH's hydroelectric projects at relicensing or that the projects will be abandoned, surrendered or the project licenses revoked.  However, it is impossible to predict the outcome of the FERC relicensing proceedings with certainty, or to determine the impact of future regulatory actions on project economics.  Until such time as a project is ordered to be decommissioned and the terms and conditions of a decommissioning order are known, any estimates of the cost of project decommissioning are preliminary and subject to change as new information becomes available.

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EMPLOYEES

As of December 31, 2008,2010, we employed a total of 6,1896,182 employees, excluding temporary employees, of which 1,9441,847 were employed by CL&P, 1,2681,240 by PSNH, 366354 by WMECO, 417429 by Yankee Gas and 2,1822,307 were employed by Northeast Utilities Service Company (NUSCO).NUSCO.  Approximately 2,3002,212 employees of CL&P, PSNH, WMECO, NUSCO and Yankee Gas are members of the International Brotherhood of Electrical Workers and The United Steelworkers and are covered by 11 union agreements.

INTERNET INFORMATION

Our website address is www.nu.com.  We make available through our website a link to the SEC's IDEA site,EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at which site NU's, CL&P's, WMECO's and PSNH's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed. Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Northeast Utilities, 107 Selden56 Prospect Street, Berlin, Connecticut 06037.Hartford, CT 06103.

Item 1A.

Risk Factors

We are subject to a variety of significant risks inIn addition to the matters set forth under "Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995" inincluded directly prior to Item 1, "Business," above.Business, above, we are subject to a variety of significant risks.  Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks.  These risk factors should be considered carefully in evaluating our risk profile.

The infrastructureactions of regulators can significantly affect our earnings, liquidity and business activities.

The rates that our Regulated companies charge their respective retail and wholesale customers are determined by their state utility commissions and by FERC.  These commissions also regulate the companies’ accounting, operations, the issuance of certain securities and certain other matters.  FERC also regulates their transmission of electric energy, the sale of electric energy at wholesale, accounting, issuance of certain securities and certain other matters.  The commissions’ policies and regulatory actions could have a material impact on the Regulated companies’ financial position, results of operations and cash flows.

Our transmission, distribution systemand generation systems may not operate as expected, and could require additional unplanned expenseexpenditures, which could adversely affect our earnings.financial position, results of operations and cash flows.

Our ability to manage operational risk with respect toproperly operate of our transmission, distribution and distributiongeneration systems is critical to the financial performance of our business.  Our transmission, distribution and distributiongeneration businesses face several operational risks, including the breakdown or failure of or damage to equipment or processes (especially due to age), accidents and; labor disputes.  The costs (both labor and material) thatdisputes; disruptions in the delivery of electricity, including impacts on us or our regulated companies incurcustomers; increased capital expenditure requirements, including those due to construct and maintain their electric delivery systems have increased in recent years.  These increases have been driven primarily by higher demand for commodities and electrical products,environmental regulation; information security risk, such as well as increased demand for skilled labor.  A significant percentagea breach of our regulated company equipment is nearing or at the end of its life cycle,systems on which sensitive utility customer data and account information are stored; catastrophic events such as oldfires, explosions, or other similar occurrences; and obsolete distribution poles, underground primary cablesother unanticipated operations and substation switchgear.maintenance expenses and liabilities.  The failure of our transmission, distributions and distributi onsgeneration systems to operate as planned may result in increased capital investments, reduced earnings or unplanned increases in expenses, including higheroperation and maintenance costs.  Any suchAt PSNH, outages at generating stations may be deemed imprudent by state regulators resulting in disallowance of replacement power costs. Such costs which maythat are not be recoverable from our ratepayerscustomers would have an adverse effect on our earnings.financial position, results of operations and cash flows.

The global financial crisis may have impactsLimits on our access to and increases in the cost of capital may adversely impact our ability to execute our business and financial condition that we currently cannot predict.plan.

The continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial condition.  The extreme disruption in the capital markets has limited companies’ ability to access the capital and credit markets to support their operations and refinance debt and has led to higher financing costs compared to recent years. We use short-term debt and the long-term capital markets as a significant source of liquidity and funding for capital requirements not satisfied byobtained from our operating cash flow, including construction costs.  Theflow.  If access to these sources of liquidity becomes constrained, our ability to implement our business strategy could be adversely affected.  In addition, higher interest rates would increase our cost of debt financingborrowing, which could adversely impact our results of operations.  A downgrade of our credit ratings or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the proceeds of equity financing may be materially adversely impacted by these market conditions.  The inability to raise capital on favorable terms couldmarkets and negatively affect our ability to maintain and to expand our businesses.

Our current credit ratings cause us to believe that we will continue to have access to t he capital markets. However, events beyond our control, such as the disruption in global capital and credit markets in 2008,counterparties may create uncertainty that could increase our cost of capital or impair our ability to access the capital markets.  In addition, certain of NU parent’s subsidiaries rely, in part, on NU parent for access to capital.  Circumstances that limit NU parent’s access to capital could impair its ability to provide those companies with needed capital.  The credit crisis could also have an impact on our lenders or our customers, causing them to fail tonot meet their obligations to us.  Additionally, the crisis could have a broader impact on business in general in ways that could lead to reduced electricity and gas usage, which could have a negative impact on our revenues.

In addition,We are exposed to the consequencesrisk that counterparties to various arrangements who owe us money, or have contracted to supply us with energy, coal, or other commodities or services, or who work with us as strategic partners, including on significant capital projects, will not be able to perform their obligations or, with respect to our credit facilities, fail to honor their commitments.  Should any of these counterparties fail to perform their obligations, we might be forced to replace the underlying commitment at higher market prices and/or have to delay the completion of a prolonged recession may include a lowercapital project.  Should any lenders under our credit facilities fail to perform, the level of economic activity and uncertainty regarding energy prices.  A lower levelborrowing capacity under those arrangements could decrease.  In any such events, our financial position, results of economic activity might result in a decline in energy consumption, which mayoperations, or cash flows could be adversely affect our revenues and future growth.  Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses.affected.

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Changes in regulatory or legislative policy and/or regulatory decisions, difficulties in obtaining siting, design or other approvals, global demand for critical resources, or environmental or other concerns, or construction of new generation may delay completion of or displace our planned transmission projects or adversely affect our ability to recover our investments or result in lower than expected rates of return.

The successful implementation of ourOur transmission construction plans is subject to the risk thatcould be affected by new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations could impact our ability to meet our construction schedule and/or require us to incur additional expenses and may adversely affect our ability to achieve forecast levels of revenues.  In addition, difficultiesregulatory decisions, delays in obtaining required approvals for construction, or increased cost of and difficulty in obtaining critical resources as a resultrequired for construction.  Any of global or

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domestic demand for such resourcesevents could cause delays in our construction schedule and may adversely affectaffecting our ability to achieve forecasted earnings.

The regulatory approval process for our planned transmission projects encompasses anrequires extensive permitting, design and technical approval process.activities.  Various factors could result in increased cost estimatescosts and delayed construction.delay construction schedules.  These include environmental and community concerns and design and siting issues.  Recoverability of all such investments in rates may be subject to prudence review at the FERC.  While we believe that all such expensescosts have been and will be prudently incurred, we cannot predict the outcome of future reviews should they occur.

In addition, to the extent that new generation facilities are proposed or built to address the region’s energy needs, the need for our planned transmission projects may be delayed or displaced by new generation facilities, which could result in reduced transmission capital investments, reduced earnings, and limited future growth prospects.

The currently plannedMany of our transmission projects are expected to help alleviate identified reliability issues and to help reduce customers' costs.  However, if, due to further regulatory or other delays, the projected in-service date for one or more of these projects is delayed, there may be increased risk of failures in the existing electricity transmission system and supply interruptions or blackouts, may occur which could have an adverse effect on our earnings.

The FERC has followed a policy of providing incentives designed to encourage the construction of new transmission facilities, including higher returns on equity and allowing facilities under construction to be placed in rate base before completion.base. Our projected earnings and growth could be adversely affected were FERC to reduce these incentives in the future below the level presently anticipated.

Increases in electric and gas prices the continued economic slowdown and focus on conservation and self-generation by customers andand/or a weak economy, can lead to changes in legislative and regulatory policy promoting energy efficiency, conservation, and self-generation and/or a reduction in our customers’ ability to pay their bills, which may adversely impact our business.

The nation's economy has been affectedEnergy consumption is significantly impacted by significant increasesthe general level of economic activity and cost of energy supply.  Economic downturns or periods of high energy supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy prices, particularly fossil fuels, as well as by a general economic slowdown.  The impact of these increases has led toconsumption and increased electricity and natural gas prices for our customers, which, coupled with the continued economic slowdown, has increased the focus on conservation, energy efficiency and self-generation on the part of customers and on legislative and regulatory policies.by customers.  This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and gas sales in our service territories.  If any such declines were to occur without corresponding adjustments in rates, then our revenues would be reduced and our future growth prospects would be limited.

In addition, a period of prolonged economic weakness could impact customers’ ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses or other adverse effects on our financial position, results of operations or cash flows.

Connecticut, New Hampshire and Massachusetts have each announced policies aimed at increased energy efficiency and conservation.  In connection with such policies, all three states have opened proceedings to investigateinvestigated revenue decoupling as a mechanism to align the interests of customers and utilities relative to conservation.  In Connecticut, the DPUC authorized decoupling viathrough a rate design that is intended to recover proportionately greater distribution revenue through the fixed Customer and Demand charges, and proportionately less distribution revenue through usage-based charges.  In New Hampshire, the per kWh charges .NHPUC conducted a decoupling docket and determined that utilities were free to propose decoupling in the context of a rate case and demonstrate the effect decoupling would have on its risk profile and ROE.  PSNH has not yet commenced such a proceeding.  In Massachusetts, the DPU has required WMECO to adopt full decoupling in its January 31, 2011 rate decision.  At this time it is uncertain what mechanisms will ultimately be adopted by New Hampshire and Massachusetts and what impact these decoupling mechanisms will have on our companies.

ChangesAs a way to promote self-generation and reduce energy costs, Connecticut, Massachusetts, and New Hampshire have taken a greater interest in regulatory policy may adversely affect our transmission franchise rightsallowing customers to receive credit for generation produced at a customer-owned generating facility that exceeds their energy needs.  In Massachusetts, in accordance with the Green Communities Act, the DPU adopted rules and regulations concerning net metering that will have this effect. Such rules provide a cost recovery mechanism for affected utilities to recover lost revenues.  The Massachusetts DPU is expected to hold further proceedings to address net metering in early 2011.  In Connecticut, the DPUC opened a docket to review existing state statutes and determine what limitations currently exist in state law concerning net metering.  In addition, any legislation in Connecticut to promote self-generation and net metering could impact CL&P’s financial position, results of operations or facilitate competitioncash flows.  In New Hampshire, new legislation dramatically changed the net metering rules in 2010.  This new legislation is meant to encourage net metering from customers with small generators and also provides PSNH a cost recovery mechanism for construction of large-scale transmission projects, which could adversely affect our earnings.

We have undertaken a substantial transmission capital investment program and expect to invest approximately $3.5 billion in regulated electric transmission infrastructure from 2009 through 2013.

Although our public utility subsidiaries have exclusive franchise rights for transmission facilities in our service area, the demand for improved transmission reliability could result in changes in federal or state regulatory or legislative policy that could cause us to lose the exclusivity of our franchises or allow other companies to compete with us for transmission construction opportunities.  Such a change in policy could result in reduced transmission capital investments, reduce earnings, and limit future growth prospects.lost distribution revenue.   

Changes in regulatory and/or legislative policy could negatively impact regional transmission cost allocation rules.

The existing FERC-approved New England transmission tariff allocates the costs of transmission investmentfacilities that provide regional benefits to all customers in New England.of participating transmission-owning utilities.  As new investment in regional transmission infrastructure occurs in any one state, thereits cost is a sharing of these regional costsshared across all of New England.England in accordance with relative benefits received.  This regional cost allocation is contractually agreed to byset forth in the Transmission Operating Agreement signed by all of the New England transmission owning utilities bututilities.  Effective February 1, 2010, this agreement can be changedmodified with the approval of a majority of the transmission owning utilities after February 1, 2010.and FERC.  In addition, after that date, other parties, such as state regulators, may seek certain changes to the regional cost allocation formula, which could have adverse effects on the

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rates our distribution companies' local rates.  We are workingcompanies charge their retail customers.  FERC is also considering policies to retainencourage the existing regional cost allocation treatment but cannot predictconstruction of transmission for renewable generation that could have the actionseffect of the states or utilities in the region.imposing costs of inter-regional investment on New England customers.

Changes in regulatory or legislative policy or unfavorable outcomes in regulatory proceedings could jeopardize our full and/or timely recovery of costs incurred by our regulated distribution companies.and generation businesses.

Under state law, our utilityRegulated companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.  Each of these companies prepares and submits periodic rate filings with their respective state regulatory commissions for review and approval.  There is no assurance that these state commissions will approve the recovery of all such costs prudently incurred

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by our regulatedRegulated companies, such as for construction, operation and maintenance, construction, as well as a return on investment on their respective regulated assets.  Increases in these costs, coupled with increases in fuel and energy prices could lead to consumer or regulatory resistance to the timely recovery of such prudently incurred costs, thereby adversely affecting our cash flows andfinancial position, results of operations.operations or cash flows.  Additionally, state legislators may enact laws that significantly impact our Regulated companies’ revenues, including by mandating electric or gas rate relief and/or by requiring surcharges to customer bills to support state programs not related to the utilities or energy policy.  Such increases could pressure overall rates to our customers and our routine requests to regulators for rate relief.

In addition, CL&P and WMECO procure energy for a substantial portion of their customerscustomers’ needs via requests for proposal on an annual, semi-annual or quarterly basis.  CL&P and WMECO receive approvals of recoveryapproval to recover the costs of these contract pricescontracts from the DPUC and DPU, respectively.  While both regulatory agencies have consistently approved the solicitation processes, results and recovery of costs, management cannot predict the outcome of future solicitation efforts or the regulatory proceedings related thereto.

ThePSNH meets most of its energy requirements for PSNH are currently met primarily through PSNH'sits own generation resources orand fixed-price forward purchase contracts.  PSNH’s remaining energy needs are met primarily through spot market or bilateral energy purchases.  Unplanned forced outages of its generating plants could increase the level of energy purchases needed by PSNH and therefore increase the market risk associated with procuring the necessary amount of energy to meet its requirements.  PSNH recovers these costs through its ES rate, subject to a prudence review by the NHPUC.  We cannot predict the outcome of future regulatory proceedings related to recovery of these costs.

Migration of customers from PSNH energy service to competitive energy suppliers could increase the cost to the remaining customers of energy produced by PSNH generation assets and decrease our revenues.

PSNH’s ES rates have been higher than competitive energy prices offered to some customers in recent years, primarily due to lower natural gas prices.  As a result, by the end of 2010, approximately 2 percent of PSNH’s retail customers (representing approximately 32 percent of load), mostly large commercial and industrial customers, were buying their energy from competitive suppliers rather than from PSNH.  The remaining retail customers are experiencing an increase in the cost of energy service supplied by PSNH by 5 percent to 7 percent due to migration of large commercial and industrial customers and the lower base in which to recover PSNH's fixed generation costs.  This increase may in turn cause further migration and further increasing of PSNH energy service rates.  This trend could lead to PSNH continuing to lose retail customers and increasing the burden of supporting the cost of its generation faciliti es on remaining customers and being unable to support the cost of its generation facilities through an ES rate.  

The NHPUC is examining this issue in a proceeding in which hearings ended on December 1, 2010.  PSNH has suggested transferring some fixed costs of the generation facilities into a nonbypassable charge while intervening competitive suppliers have proposed taking over the purchased power portion of the load not supplied by PSNH’s generation.  Others have also proposed having PSNH bid all of its generation facilities into the market while an RFP process supplies all of the power for PSNH’s energy service.  The NHPUC is considering further proceedings to explore these and other issues as well as the NHPUC authority to require PSNH to divest its generation facilities.  It is not known what the results of such a proceeding would be, what PSNH may realize as a result of the sale or retirement of one or more of its generation facilities, or to what extent or manner the NHPUC would provide for recovery of any invest ment in its generation facilities.  

Judicial or regulatory proceedings or changes in regulatory or legislative policy could jeopardize completion of, or full recovery of costs incurred by PSNH in constructing, the Clean Air Project.

Pursuant to New Hampshire law, PSNH has begun work onis building the Clean Air Project at its Merrimack Station in Bow, New Hampshire.  As a result of an increase in the estimated cost of the project from $250 million to $457 million, severalSeveral parties have initiated legal proceedings challenging the project.  These proceedings, or new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations could result in increased costs to the delay or cancelation of this project or add to its cost.  Any delay or cancelation of the project would adversely affect our ability to achieve forecast levels of earnings.  If the project were to be canceled, contract payments and termination costs would be a substantial portion of the contractual commitments entered into by PSNH. As of March 31, 2009, the contractual commitments are expected to total approximately $250 million.  The actual amount of contract termination costs wo uld depend on timing of the cancelation and negotiations with the contractors.  At this time, we cannot predict any legislative or regulatory changes or the outcome of the pending legal proceedings.project.

In addition, PSNH’s investment in the project after it is completed is subject to prudence review by the NHPUC at the time the project is placed in service.  A material prudence disallowance of a material nature could adversely affect PSNH’s cash flows andfinancial position, results of operations.operations or cash flows.  While we believe thatwe have prudently incurred all expenditures to date, have been prudently incurred, we cannot predict the outcome of any prudency reviews should they occur.  Our projected earnings and growth could be adversely affected were the NHPUC to deny recovery of some or all of PSNH’s investment in the project.

The loss of key personnel or the inability to hire and retain qualified employees could have an adverse effect on our business, financial condition and results of operations.

Our operations depend on the continued efforts of our employees.  Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance.  We cannot guarantee that any member of our

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management or any key employee at the NU parent or subsidiary level will continue to serve in any capacity for any particular period of time.  In addition, a significant portion of our workforce, including many workers with specialized skills maintaining and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years.  Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform.  We are developinghave developed strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce, but cannot predict the impact of these plans on our ability to hire and retain key employees.

Grid disturbances, severe weather, or acts of war or terrorism could negatively impact our business.

Because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business continuity due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage, solar storm activity or terrorist action) on an interconnected system or the actions of another utility.  In addition, we are subject to the risk that acts of war or terrorism, including cyber-terrorism could negatively impact the operation of our system.  Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition, and results of operations.operations or cash flows.

Severe weather, such as ice and snow storms, such as the ice storm that impacted New Hampshire in December 2008, hurricanes and other natural disasters, may cause outages and property damage, which may require us to incur additional costs that are generally not insured and that may not be recoverable from customers.  The cost of repairing damage to our operating subsidiaries' facilities and the potential disruption of their operations due to storms, natural disasters or other catastrophic events could be substantial.substantial, particularly as customers demand better and quicker response times to outages.  The effect of the failure of our facilities to operate as planned would be particularly burdensome during a peak demand period, such as during the hot summer months.

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A negative changeMarket performance or changes in NU's credit ratingsassumptions could require NU parentus to post cash collateralmake significant contributions to our pension and affect our ability to obtain financing.other post-employment benefit plans.

NU parent’s senior unsecured debt ratings by Moody's Investors Service, Standard & Poor's, Inc.We provide a defined benefit pension plan and Fitch Ratingsother post-retirement benefits for a substantial number of employees, former employees and retirees.  Our future pension obligations, costs and liabilities are currently Baa2, BBB-highly dependent on a variety of factors beyond our control.  These factors include estimated investment returns, interest rates, health care cost trends, benefit changes, salary increases and BBB, respectively, with stable outlooks.  Were anythe demographics of these ratingsplan participants.  If our assumptions prove to declinebe inaccurate, our future costs could increase significantly.  In 2008 and 2009, due to non-investment grade level, Select Energythe financial crisis, the value of our pension assets declined.  As a result, we made a contribution of $45 million in 2010 and expect to make an approximate $145 million contribution in 2011.  In addition, various factors, including underperformance of plan investments and changes in law or regulation, could be asked to provide, as of December 31, 2008, collateral in the form of cash or letters of credit inincrease the amount of $23.2 millioncontributions required to unaffiliated counterparties and cash or letters of creditfund o ur pension plan in the future.  Additional large funding requirements, when combined with the financing requirements of our construction program, could impact the timing and amount of $10 million to two independent system operators.  Whilefuture equity and debt financings and negatively affect our credit facilities are sufficient in amounts that would be adequate to meet collateral calls at that level, our ability to meet any future collateral calls would depend on our liquidity and access to bank lines and the capital markets at such time.financial position, results of operations or cash flows.  

Changes in wholesale electric sales could require Select Energy to acquire or sell additional electricity on unfavorable terms.

Select Energy's remaining wholesale sales contracts provide electricity to full requirements customers, including a municipal electric company.  Select Energy provides a portion of the customer's electricity requirements.  The volumes sold under these contracts vary based on the usage of the underlying retail electric customers, and usage is dependent upon factors outside of Select Energy's control, such as economic activity and weather.  The varying sales volumes may differ from the supply volumes that Select Energy expected to utilize from electricity purchase contracts.  Differences between actual sales volumes and supply volumes may require Select Energy to purchase additional electricity or sell excess electricity, both of which are subject to market conditions which change due to weather, plant availability, transmission congestion, and input fuel costs.  The purchase of additional electricity at high pri ces or sale of excess electricity at low prices could negatively impact Select Energy's cost to serve the contracts.

Costs of compliance with environmental regulations, including climate change legislation, may increase and have an adverse effect on our business and results of operations.

Our subsidiaries' operations are subject to extensive federal, state and local environmental statutes, rules and regulations which regulate,that govern, among other things, air emissions, water discharges and the management of hazardous and solid waste.  Compliance with these requirements requires us to incur significant costs relating to environmental monitoring, installation of pollution control equipment, emission fees, maintenance and upgrading of facilities, remediation and permitting.  The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future.  An increase in such costs, unless promptly recovered, could have an adverse impact on our business and our financial position, results of operations financial position andor cash flows.

In addition, global climate change issues have received an increased focus on thefrom federal and state government levelsgovernments, which could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the power plants we own and operate as well as general utility operations.  Although we would expect that any costs of these rules and regulations would be recovered from ratepayers, thecustomers, their impact of these rules and regulations on energy use by ratepayerscustomers and the ultimate impact on our business would be dependent upon the specific rules and regulations adopted and cannot be determined at this time.  The impact of these additional costs to customers could lead to a further reduction in energy consumption resulting in a decline in electricity and gas sales in our service territories, which would have an adverse impact on our business and financial position, results of operations or cash flows.

Any failure by us to comply with environmental laws and regulations, even if due to factors beyond our control, or reinterpretations of existing requirements, could also increase costs.  Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us.  Revised or additional laws could result in significant additional expense and operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable in distribution company rates for generation.rates.  The cost impact of any such legislationlaws, rules or regulations would be dependent upon the specific requirements adopted and cannot be determined at this time.  For further information, see Item 1, "BusinessBusiness - Other"Other Regulatory and Environmental Matters, - Environmental Regulation"" in this Annual Report on Form 10-K.

We are subjectAs a holding company with no revenue-generating operations, NU parent is dependent on dividends from its subsidiaries, primarily the Regulated companies, its bank facility, and its ability to legal proceedings whichaccess the long-term debt and equity capital markets.

NU parent is a holding company and as such, has no revenue-generating operations of its own.  Its ability to meet its financial obligations associated with the debt service obligations on its debt and to pay dividends on its common shares is largely dependent on the ability of its subsidiaries to pay dividends to or to repay borrowings from NU parent; and/or NU parent’s ability to access its credit

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facility or the long-term debt and equity capital markets.  Prior to funding NU parent, the Regulated companies have financial obligations that must be satisfied, including among others, their operating expenses, debt service, preferred dividends (in the case of CL&P) and obligations to trade creditors.  Additionally, the Regulated companies could resultretain their free cash flow to fund their capital expenditures in large cash obligations.  lieu of receiving equity contributions from NU parent.  Should the Regulated companies not be able to pay dividends to or repay funds due to NU parent or if NU parent cannot access its bank facilities or the long-term debt and equity capital markets, NU parent’s ability to pay interest, dividends and its own debt obligations would be restricted.

Risks Related to the Proposed Merger with NSTAR

We are engaged in legal proceedings thatmay be unable to satisfy the conditions or obtain the approvals required to complete the merger or such approvals may contain material restrictions or conditions.

The merger is subject to approval by the shareholders of both NU and NSTAR and numerous other conditions, including the approval of various government agencies.  Governmental agencies may not approve the merger or such approvals may impose conditions on the completion, or require changes to the terms of the merger, including restrictions on the business, operations or financial performance of the combined company, which could result inbe adverse to the impositioncompany's interests.  These conditions or changes could also delay or increase the cost of large cash obligations against us.  the merger or limit the net income or financial prospects of the combined company.

We may alsowill be subject to future legal proceedings based on asserted or unasserted claimsbusiness uncertainties and cannot predictcontractual restrictions while the outcome of any of these proceedings.  Adverse outcomes in existing or future legal proceedings could result in the imposition of substantial cash damage awards or cash obligations against us.merger is pending.

Further information regarding legal proceedings,The work required to complete the merger may place a significant burden on management and internal resources.  Management's attention and other company resources may be focused on the merger instead of on day-to-day management activities, including pursuing other opportunities beneficial to NU.  In addition, while the merger is pending our business operations are restricted by the Agreement and Plan of merger to ordinary course of business activities consistent with past practice, which may cause us to forgo otherwise beneficial business opportunities.

We may lose management personnel and other key employees and be unable to attract and retain such personnel and employees.

Uncertainties about the effect of the merger on management personnel and employees may impair our ability to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter, which could affect our financial performance.

The merger may not be completed, which may have an adverse effect on our share price and future business and financial results and we could face litigation concerning the merger, whether or not the merger is consummated.

Failure to complete the merger could negatively affect NU's share price, as well as other matters, is set forthour future business and financial results.  In addition, purported class actions have been brought against us, NSTAR and others on behalf of holders of NSTAR common shares.  If these actions or similar actions that may be brought are successful, the costs of completing the merger could increase, or the merger could be delayed or prevented.  We cannot make any assurances that we will succeed in any litigation brought in connection with the merger.  See Item 3, "Legal Proceedings."Legal Proceedings, in this Annual Report on Form 10-K for discussion of pending litigation related to the merger.  

If the merger is not completed for certain reasons specified in the merger agreement, we may be required to pay NSTAR a termination fee of $135 million plus up to $35 million of certain expenses incurred by NSTAR.  In addition, we must pay our own costs related to the merger including, among others, legal, accounting, advisory, financing and filing fees and printing costs, whether the merger is completed or not.  Further, if the merger is not completed, we could be subject to litigation related to the failure to complete the merger or other factors, which may adversely affect our business, financial results and share price.

If completed, the merger may not achieve its intended results.

We entered into the merger agreement with the expectation that the merger would result in various benefits. If the merger is completed, our ability to achieve the anticipated benefits will be subject to a number of uncertainties, including whether our businesses can be integrated in an efficient and effective manner.  Failure to achieve these anticipated benefits could adversely affect our business, financial results and share price.   

Item 1B.

Unresolved Staff Comments

We do not have any unresolved SEC staff comments.  

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KV; 34,89734,957 pole miles of overhead and 2,9253,054 conduit bank miles of underground distribution lines; and 536,203539,379 underground and overhead line transformers in service with an aggregate capacity of 36,730,94037,703,193 kVa.

Electric Generating Plants

As of December 31, 2008,2010, PSNH owned the following electric generating plants:  

*

Claimed capability represents winter ratings as of December 31, 2008.2010.  The combined nameplate capacity of the generating plants is approximately 1,200 MW.

Neither As of December 31, 2010, WMECO owned the following electric generating plant:  

** Claimed capability represents the direct current nameplate capacity of the plant.

CL&P nor WMECO owneddid not own any electric generating plants during 2008.2010.

Yankee Gas

AtAs of December 31, 2008,2010, Yankee Gas owned 2728 active gate stations, approximately 270200 district regulator stations and 3,2003,239 miles of natural gas main gas pipelines.pipeline.  Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, as well asa propane facility in Kensington, Connecticut, and three additional propane facilities that are no longer in Danbury, Kensingtonservice and Vernon, Connecticut.are expected to be sold in 2011.

Franchises

CL&P.  Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services in the respective areas in which it is now supplying such service.

In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth in Title 16 of the Connecticut General Statutes and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and/or sell electricity at retail, including to provide Standard Service, Supplier of Last Resort service and backup service, to sell electricity at wholesale and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain.  Title 16 of the Connecticut General Statutes was amended by Public Act 03-135, "An Act Concerning Revisions to the Electric Restructuring Legislation," to prohibit an electric distribu tiondistributi on company from owning or operating generation assets.  However, Public Act 05-01, "An Act Concerning Energy Independence," allows CL&P to own up to 200 MW of peaking facilities if the DPUC determines that such facilities will be more cost effective than other options for mitigating FMCCs and LICAPLocational Installed Capacity (LICAP) costs.  In addition, Section 83 of Public Act 07-242, "An Act Concerning Electricity and Energy Efficiency"Efficiency," states that if an existing electric generating plant located in Connecticut is offered for sale, then an electric distribution company, such as CL&P, would be eligible to purchase the generation plant upon obtaining prior approval from the DPUC and a determination by the DPUC that such purchase is in the public interest.  

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PSNH.  The NHPUC, pursuant to statutory requirements, has issued orders granting PSNH exclusive franchises to distribute electricity in the respective areas in which it is now supplying such service.  

In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law.  The distribution and transmission franchises of PSNH include the power of eminent domain.  

WMECO.  WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines.  Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested.  Such locations are for specific lines only and for extensions of lines in public highways.  Further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities.  In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority and pursuant to state laws, has the power of eminent domain.  On December 31, 2008, WMECO purchased all of the transmission-related assets of its affiliates, HWP and HP&E, for approximately $4 million.

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The Massachusetts restructuring legislation defines service territories as those territories actually served on July 1, 1997 and following municipal boundaries to the extent possible.  The restructuring legislation further provides that until terminated by law or otherwise, distribution companies shall have the exclusive obligation to serve all retail customers within their service territories and no other person shall provide distribution service within such service territories without the written consent of such distribution companies. Pursuant to the Massachusetts restructuring legislation, the DPU (then, the Department of Telecommunications and Energy) was required to define service territories for each distribution company, including WMECO.  The DPU subsequently determined that there were advantages to the exclusivity of service territories and issued a report to the Massachusetts Legislatu reLegislature recommending against, in this regard, any changes to the restructuring legislation.

Holyoke Water and Power Company and Holyoke Power and Electric Company.  HWP, and its wholly owned subsidiary HP&E, are authorized by their charters to conduct their businesses in the territories served by them.  In connection with the sale of certain of HWP's and HP&E's assets to the city of Holyoke Gas and Electric Department (HG&E) effective December 2001, HWP agreed not to distribute electricity at retail in Holyoke and surrounding towns unless other sellers can legally compete with HG&E, and to amend the charters of HWP and HP&E to reflect that limitation.  

Prior to December 31, 2008, the two companies had locations in the public highways for their transmission lines.  Such locations were granted pursuant to the laws of Massachusetts by the Massachusetts Department of Public Works or by local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested.  Such locations are for specific lines only and, for extensions of lines in public highways, further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities.  HP&E has no retail service territory area and sells electric power exclusively at wholesale.  On December 31, 2008, HWP and HP&E sold all of their transmission-related assets to WMECO.

Yankee Gas.Yankee Gas directly and from its predecessors in interest holds valid franchises to sell gas in the areas in which Yankee Gas supplies gas service.service, which it acquired either directly or from its predecessors in interest.  Generally, Yankee Gas holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Connecticut so long as those areas are not occupied and served by another gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another gas utility.  Yankee Gas’sGas’ franchises are perpetual but remain subject to the power of alteration, amendment or repeal by the General Assembly of the State of Connecticut, the power of revocation by the DPUC and certain approvals, permits and consents of public authorities and others prescribed by statute.  Generally, Yankee Gas’sGas’ franchises include, among other rights and powers, the right and power to manufacture,manuf acture, generate, pur chase,purchase, transmit and distribute gas and to erect and maintain certain facilities on public highways and grounds, and the right of eminent domain, all subject to such consents and approvals of public authorities and others as may be required by law.

Item 3.

Legal ProceedingsPart II

1.Item 5.

Yankee Companies v. U.S. Department of Energy

Yankee Atomic Electric Company (YAEC), Maine Yankee Atomic Power Company (MYAPC), and Connecticut Yankee Atomic Power Company (CYAPC) (the Yankee Companies) commenced litigation in 1998 against the United States Department of Energy (DOE) charging that the federal government breached contracts it entered into with each company in 1983 under the Nuclear Waste Policy Act of 1982 to begin removing spent nuclear fuel from the respective nuclear plants no later than January 31, 1998 in return for payments by each company into the Nuclear Waste Fund. The funds for those payments were collected from regional electric customers.  The Yankee Companies initially claimed damages for incremental spent nuclear fuel storage, security, construction and other costs through 2010.

In a ruling released in 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002.  CL&P, PSNH and WMECO expect to pass any recovery onto their customers, therefore, no earnings impact is expected to result.  In December 2006, the DOE appealed the decision and the Yankee Companies filed cross-appeals.  The Court of Appeals disagreed with the trial court’s method of calculation of the amount of the DOE’s liability, among other things, and vacated the decision of the Court of Federal Claims and remanded the case to make new findings consistent with its decision.  The application of any damages which are ultimately recovered to benefit customers is established in the Yankee Companies' FERC-approved rate settlement agreements, although implementation will be subject to the final determination of the FERC.

In December 2007, the Yankee Companies filed a second round of lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002.

2.

Connecticut MGP Cost Recovery

On August 5, 2004, Yankee Gas and CL&P (NU Companies) demanded contribution from UGI Utilities, Inc. (UGI) of Pennsylvania for past and future remediation costs related to historic MGP operations on thirteen sites currently or formerly owned by the NU Companies (Yankee Gas is responsible for ten of the sites, CL&P for two of the sites, and both companies share responsibility for one site) in a number of different locations throughout the State of Connecticut.  The NU Companies alleged that UGI controlled operations of the plants at various times throughout the period 1883 to 1941, when UGI was forced to divest its interests.  Investigations and remediation expenditures at the sites to date total over $20 million, and projected potential remediation costs for all sites, based on litigation modeling assumptions, could total as much as $232 million.  At this point, we are unable to estimate the potential costs assoc iated with this matter.

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In September 2006, the NU Companies filed a complaint against UGI in the U.S. District CourtMarket for the DistrictRegistrants' Common Equity and Related Stockholder Matters

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Item 6.

Selected Consolidated Financial Data

24

Item 7.

Management's Discussion and Analysis of Connecticut seeking a fairFinancial Condition and equitable contribution for the actualResults of Operations

26

Item 7A.

Quantitative and anticipated remediation costs related to the former MGP operations. The trial has been scheduled for April 2009.

3.

Other Legal Proceedings

For further discussion of legal proceedings see the following sections of Item 1, "Business": "Regulated Electric Distribution," "Regulated Gas Operations," and "Regulated Electric Transmission" for informationQualitative Disclosures about various state regulatory and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues; "Nuclear Decommissioning" for information related to high-level nuclear waste; and "Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality requirements, toxic substances and hazardous waste, EMF, licensing of hydroelectric projects, and other matters. In addition, see Item 1A, "Risk Factors" for general information about several significant risks.Market Risk

70

Item 4.8.

Submission Of Matters To a VoteFinancial Statements and Supplementary Data

72

Item 8A.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

160

Item 8B.

Controls and Procedures

160

Item 9.

Other Information

160

Part III

Item 10.

Directors, Executive Officers and Corporate Governance

161

Item 11.

Executive Compensation

162

Item 12.

Security Ownership of Security HoldersCertain Beneficial Owners and Management and Related Stockholder Matters

195

Item 13.

Certain Relationships and Related Transactions, and Director Independence

197

Item 14.

Principal Accountant Fees and Services

197

Part IV

Item 15.

Exhibits and Financial Statement Schedules

199

Signatures

200