____________________________________________________________________________________  [march2009form10qedgar001.jpg]  UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q  [X]QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE     
SECURITIES EXCHANGE ACT OF 1934For the Quarterly Period Ended March 31, 2009OR[  ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE     
SECURITIES EXCHANGE ACT OF 1934For the transition period from ____________ to ____________  CommissionFile NumberRegistrant; State of Incorporation;Address; and Telephone NumberI.R.S. EmployerIdentification No.1-5324NORTHEAST UTILITIES(a Massachusetts voluntary association)
One Federal Street
Building 111-4
Springfield, Massachusetts 01105
Telephone:  (413) 785-587104-21479290-00404THE CONNECTICUT LIGHT AND POWER COMPANY(a Connecticut corporation)
107 Selden Street
Berlin, Connecticut 06037-1616 
Telephone:  (860) 665-500006-03038501-6392PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 
(a New Hampshire corporation)
Energy Park
780 North Commercial Street
Manchester, New Hampshire 03101-1134
Telephone:  (603) 669-400002-01810500-7624WESTERN MASSACHUSETTS ELECTRIC COMPANY(a Massachusetts corporation)
One Federal Street
Building 111-4
Springfield, Massachusetts 01105
Telephone:  (413) 785-587104-1961130 ____________________________________________________________________________________    Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days:  YesNoÖ  Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  YesNo  Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.  (check one):  Large
Accelerated FilerAccelerated
FilerNon-accelerated
FilerNortheast UtilitiesÖThe Connecticut Light and Power CompanyÖPublic Service Company of New HampshireÖWestern Massachusetts Electric CompanyÖ  Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act):  YesNoNortheast UtilitiesÖThe Connecticut Light and Power CompanyÖPublic Service Company of New HampshireÖWestern Massachusetts Electric CompanyÖ  Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date: Company - Class of StockOutstanding at April 30, 2009Northeast Utilities
Common shares, $5.00 par value175,129,250 sharesThe Connecticut Light and Power Company
Common stock, $10.00 par value6,035,205 sharesPublic Service Company of New Hampshire
Common stock, $1.00 par value301 sharesWestern Massachusetts Electric Company
Common stock, $25.00 par value434,653 shares  Northeast Utilities holds all of the 6,035,205 shares, 301 shares, and 434,653 shares of the outstanding common stock of The Connecticut Light and Power Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company, respectively.  Public Service Company of New Hampshire and Western Massachusetts Electric Company each meet the conditions set forth in General Instructions H(1)(a) and (b) of Form 10-Q, and each is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) of Form 10-Q.      GLOSSARY OF TERMSThe following is a glossary of frequently used abbreviations or acronyms that are found in this report.CURRENT OR FORMER NU COMPANIES, SEGMENTS OR INVESTMENTS:BoulosE.S. Boulos CompanyCL&PThe Connecticut Light and Power CompanyHWPHolyoke Water Power CompanyNAESCONorth Atlantic Energy Service CompanyNGCNortheast Generation CompanyNGSNortheast Generation Services Company and subsidiariesNU or the companyNortheast UtilitiesNU EnterprisesNU Enterprises, Inc. is the parent company of Select Energy, NGS, SECI and Boulos.  For further information, see Note 9, "Segment Information," to the condensed consolidated financial statements.NUSCONortheast Utilities Service CompanyNU parent and other companiesNU parent and other companies is comprised of NU parent, NUSCO, HWP (through December 31, 2008) and other subsidiaries, including The Rocky River Realty Company and The Quinnehtuk Company (both real estate subsidiaries), Mode 1 Communications, Inc. (telecommunications) and the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company, Yankee Energy Financial Services Company, and NorConn Properties, Inc.)PSNHPublic Service Company of New HampshireRegulated companiesNU's regulated companies, comprised of the electric distribution and transmission segments of CL&P, PSNH and WMECO, the generation segment of PSNH, and Yankee Gas, a natural gas local distribution company.  For further information, see Note 9, "Segment Information," to the condensed consolidated financial statements.SECISelect Energy Contracting, Inc.Select EnergySelect Energy, Inc.SESISelect Energy Services, Inc.WMECOWestern Massachusetts Electric CompanyYankeeYankee Energy System, Inc.Yankee GasYankee Gas Services CompanyREGULATORS:DPUMassachusetts Department of Public UtilitiesDPUCConnecticut Department of Public Utility ControlFERCFederal Energy Regulatory CommissionNHPUCNew Hampshire Public Utilities CommissionSECSecurities and Exchange Commission   i     OTHER:AFUDCAllowance For Funds Used During ConstructionCfDContract for DifferencesCO2Carbon DioxideCTACompetitive Transition AssessmentEPSEarnings Per ShareESDefault Energy ServiceFASBFinancial Accounting Standards BoardFMCCFederally Mandated Congestion ChargesFSPFASB Staff PositionGAAPAccounting principles generally accepted in the United States of AmericaGSCGeneration Service ChargeISO-NENew England Independent System Operator or ISO New England, Inc.KWHKilowatt-HoursKVKilovoltLBCBLehman Brothers Commercial Bank, Inc.LOCLetter of CreditMWMegawattsMWHMegawatt-HoursNEEWSNew England East-West SolutionsNU 2008 Form 10-KThe Northeast Utilities and Subsidiaries combined 2008 Annual Report on Form 10-K as filed with the SECNYMPANew York Municipal Power AgencyPBOPPostretirement Benefits Other Than PensionsPCRBsPollution Control Revenue BondsRegulatory ROEThe average cost of capital method for calculating the return on equity related to the distribution and generation business segments excluding the wholesale transmission segment.RGGIThe Regional Greenhouse Gas InitiativeROEReturn on EquityRRBRate Reduction BondsSBCSystem Benefits ChargeSCRCStranded Cost Recovery ChargeSERPSupplemental Executive Retirement PlanSFASStatement of Financial Accounting StandardsUIThe United Illuminating Company   ii    NORTHEAST UTILITIES AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
TABLE OF CONTENTS   PagePART I - FINANCIAL INFORMATIONITEM 1 - Condensed Consolidated Financial Statements for the Following Companies:Northeast Utilities and SubsidiariesCondensed Consolidated Balance Sheets (Unaudited) - March 31, 2009 and December 31, 20082Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2009 and 20084Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2009 and 20085Combined Notes to Condensed Consolidated Financial Statements (Unaudited - all companies)6Report of Independent Registered Public Accounting Firm27The Connecticut Light and Power Company and SubsidiariesCondensed Consolidated Balance Sheets (Unaudited) - March 31, 2009 and December 31, 200830Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2009 and 200832Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2009 and 200833Public Service Company of New Hampshire and SubsidiariesCondensed Consolidated Balance Sheets (Unaudited) - March 31, 2009 and December 31, 200836Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2009 and 200838Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2009 and 200839Western Massachusetts Electric Company and SubsidiaryCondensed Consolidated Balance Sheets (Unaudited) - March 31, 2009 and December 31, 200842Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2009 and 200844Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2009 and 200845   iii     PageITEM 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations for the following  companies:Northeast Utilities and Subsidiaries46The Connecticut Light and Power Company and Subsidiaries67Public Service Company of New Hampshire and Subsidiaries70Western Massachusetts Electric Company and Subsidiary72ITEM 3- Quantitative and Qualitative Disclosures About Market Risk74ITEM 4- Controls and Procedures75PART II- OTHER INFORMATIONITEM 1- Legal Proceedings77ITEM 1A- Risk Factors77ITEM 2- Unregistered Sales of Equity Securities and Use of Proceeds77ITEM 6- Exhibits78SIGNATURES80   iv


NORTHEAST UTILITIES AND SUBSIDIARIES  1





NORTHEAST UTILITIES AND SUBSIDIARIESCONDENSED CONSOLIDATED BALANCE SHEETS(Unaudited)March 31,December 31,(Thousands of Dollars)20092008ASSETSCurrent Assets:Cash and cash equivalents$            416,828$            89,816Receivables, less provision for uncollectibleaccounts of $51,054 in 2009 and $43,275 in 2008695,599698,755Unbilled revenues198,109218,440Fuel, materials and supplies235,717300,049Marketable securities - current76,78978,452Derivative assets - current8,73431,373Prepayments and other115,39288,6791,747,1681,505,564Property, Plant and Equipment:Electric utility9,324,2379,219,351Gas utility1,051,2711,043,687Other294,296290,15610,669,80410,553,194Less:  Accumulated depreciation: $2,652,256 for electricand gas utility and $158,977 for other in 2009;$2,610,479 for electric and gas utility and$159,639 for other in 20082,811,2332,770,1187,858,5717,783,076Construction work in progress454,965424,8008,313,5368,207,876Deferred Debits and Other Assets:Regulatory assets3,437,9963,502,606Goodwill287,591287,591Marketable securities - long-term29,84130,757Derivative assets - long-term229,265241,814Other228,189212,2724,212,8824,275,040Total Assets$       14,273,586$     13,988,480The accompanying notes are an integral part of these condensed consolidated financial statements.   2





NORTHEAST UTILITIES AND SUBSIDIARIESCONDENSED CONSOLIDATED BALANCE SHEETS(Unaudited)March 31,December 31,(Thousands of Dollars)20092008LIABILITIES AND CAPITALIZATIONCurrent Liabilities:Notes payable to banks$            493,988$          618,897Long-term debt - current portion54,28654,286Accounts payable466,286678,614Accrued taxes51,40512,527Accrued interest74,68269,818Derivative liabilities - current107,147100,919Other133,452168,4011,381,2461,703,462Rate Reduction Bonds624,060686,511Deferred Credits and Other Liabilities:Accumulated deferred income taxes1,257,9741,223,461Accumulated deferred investment tax credits24,65825,371Deferred contractual obligations185,601193,016Regulatory liabilities555,519592,540Derivative liabilities - long-term897,939912,426Accrued pension743,298740,930Accrued postretirement benefits236,031240,371Other441,808430,7184,342,8284,358,833Capitalization:Long-Term Debt4,353,1804,103,162Noncontrolling Interest in Consolidated Subsidiary:Preferred stock not subject to mandatory redemption116,200116,200Common Shareholders' Equity:Common shares, $5 par value - authorized225,000,000 shares; 195,344,140 shares issuedand 175,098,530 shares outstanding in 2009 and176,212,275 shares issued and 155,834,361 sharesoutstanding in 2008976,721881,061Capital surplus, paid in1,751,4991,475,006Deferred contribution plan - employee stockownership plan(12,418)(15,481)Retained earnings1,138,9691,078,594Accumulated other comprehensive loss(37,096)(37,265)Treasury stock, 19,708,136 shares in 2009 and 2008(361,603)(361,603)Common Shareholders' Equity3,456,0723,020,312Total Capitalization7,925,4527,239,674Commitments and Contingencies (Note 5)Total Liabilities and Capitalization$       14,273,586$     13,988,480The accompanying notes are an integral part of these condensed consolidated financial statements.   3





NORTHEAST UTILITIES AND SUBSIDIARIESCONDENSED CONSOLIDATED STATEMENTS OF INCOME(Unaudited)Three Months Ended March 31,(Thousands of Dollars, except share information)20092008Operating Revenues$         1,593,483$    1,519,967Operating Expenses:Operation -Fuel, purchased and net interchange power838,920823,317Other247,445285,881Maintenance48,83656,709Depreciation76,98367,754Amortization of regulatory assets, net21,69128,855Amortization of rate reduction bonds55,89753,350Taxes other than income taxes86,42971,829Total operating expenses1,376,2011,387,695Operating Income217,282132,272Interest Expense:Interest on long-term debt55,68442,773Interest on rate reduction bonds10,62513,716Other interest4,6686,152Interest expense, net70,97762,641Other Income, Net4,18213,558Income Before Income Tax Expense150,48783,189Income Tax Expense51,42323,406Net Income99,06459,783Net Income Attributable to Noncontrolling Interests:Preferred Dividends of Subsidiary1,3901,390Net Income Attributable to Controlling Interests$              97,674$         58,393Basic and Fully Diluted Earnings Per Common Share$                  0.60$             0.38Dividends Declared Per Common Share$                  0.24$             0.20Basic Common Shares Outstanding (weighted average)162,340,475155,286,111Fully Diluted Common Shares Outstanding (weighted average)162,925,167155,721,610The accompanying notes are an integral part of these condensed consolidated financial statements.   4





NORTHEAST UTILITIES AND SUBSIDIARIESCONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS(Unaudited)Three Months Ended March 31,(Thousands of Dollars)20092008Operating Activities:Net income$             99,064$           59,783Adjustments to reconcile to net cash flowsprovided by operating activities:Bad debt expense9,5076,542Depreciation76,98367,754Deferred income taxes17,17829,009Pension and PBOP expense/(income), net of capitalized portion, and contributions6,703(2,401)Other-than-temporary impairments of marketable securities3,4623,186Regulatory refunds and underrecoveries(29,939)(84,348)Amortization/(deferral) of recoverable energy costs15,245(2,772)Amortization of regulatory assets, net21,69128,855Amortization of rate reduction bonds55,89753,350Deferred contractual obligations(8,666)(8,620)Derivative assets and liabilities(14,769)(17,208)Other(6,912)(5,948)Changes in current assets and liabilities:Receivables and unbilled revenues, net10,483(32,510)Investments in securitizable assets-33,316Fuel, materials and supplies51,17155,163Other current assets(1,541)(4,646)Accounts payable(174,497)(17,912)Margin special deposits(10,582)7,157Taxes receivable/accrued43,270(28,122)Other current liabilities(23,795)(41,902)Net cash flows provided by operating activities139,95397,726Investing Activities:Investments in property and plant(208,896)(288,135)Proceeds from sales of marketable securities52,93367,509Purchases of marketable securities(54,557)(68,564)Rate reduction bond escrow and other deposits(1,480)9,394Other investing activities2,8531,840Net cash flows used in investing activities(209,147)(277,956)Financing Activities:Issuance of common shares387,3504,041Cash dividends on common shares(37,207)(31,283)Cash dividends on preferred stock of subsidiary(1,390)(1,390)(Decrease)/increase in short-term debt(124,909)279,000Issuance of long-term debt250,000-Retirements of rate reduction bonds(62,451)(61,136)Financing fees(15,205)-Other financing activities18868Net cash flows provided by financing activities396,206190,100Net increase in cash and cash equivalents327,0129,870Cash and cash equivalents - beginning of period89,81615,104Cash and cash equivalents - end of period$           416,828$           24,974The accompanying notes are an integral part of these condensed consolidated financial statements.   5





NORTHEAST UTILITIES AND SUBSIDIARIES THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY    COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)   1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)  A. Presentation Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (SEC).  The accompanying unaudited condensed consolidated financial statements should be read in conjunction with the entirety of this combined Quarterly Report on Form 10-Q and the combined Annual Report of Northeast Utilities (NU or the company), The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO), which was filed with the SEC as part of the Northeast Utilities and subsidiaries combined 2008 Annual Report on Form 10-K (NU 2008 Form 10-K).  The accompanying condensed consolidated financial statements contain, in the opinion of management, all adjustments (including normal, recurring adjustments) necessary to present fairly NU's and the above companies' financial position at March 31, 2009 and December 31, 2008, and the results of operations and cash flows for the three months ended March 31, 2009 and 2008.  The results of operations and cash flows for the three months ended March 31, 2009 and 2008 are not necessarily indicative of the results expected for a full year.  The condensed consolidated financial statements of NU, CL&P, PSNH and WMECO include the accounts of all their respective subsidiaries.  Intercompany transactions have been eliminated in consolidation.  The preparation of the condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.  Certain reclassifications of prior period data included in the accompanying condensed consolidated financial statements have been made to conform with the current period's presentation.  In accordance with the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 160, "Noncontrolling Interests in Consolidated Financial Statements  an amendment of ARB No. 51," the preferred stock of CL&P, which is not owned by NU or its consolidated subsidiaries and is not subject to mandatory redemption, has been presented as a noncontrolling interest in CL&P in the accompanying condensed consolidated financial statements of NU.  The preferred stock of CL&P is considered to be temporary equity and has been classified between liabilities and permanent shareholders' equity on the accompanying condensed consolidated balance sheets of NU and CL&P due to a provision in CL&P's certificate of incorporation that grants preferred stockholders the right to elect a majority of CL&P's board of directors while certain conditions exist, such as if preferred dividends are in arrears for one year.  In accordance with SFAS No. 160, the net income reported in the accompanying statements of income and cash flows for NU has been revised to represent consolidated net income prior to apportionment to noncontrolling interests, which is represented by dividends on preferred stock of CL&P.  Pursuant to SFAS No. 160, the included presentation and disclosure requirements have been applied retrospectively to the condensed consolidated balance sheet as of December 31, 2008 and the statements of income and cash flows for the three months ended March 31, 2008, and to consolidated comprehensive income for the three months ended March 31, 2008 included in Note 6, "Comprehensive Income," to the condensed consolidated financial statements.  For the three months ended March 31, 2009 and 2008, there was no change in NU parents 100 percent ownership interest in common equity of CL&P.  B. Accounting Standards Issued But Not Yet Adopted In April 2009, the FASB issued FASB Staff Position (FSP) FAS 115-2 and FAS 124-2, "Recognition and Presentation of Other-Than-Temporary Impairments," which is effective as of June 30, 2009 with early adoption permitted.  The company will adopt the FSP as of June 30, 2009.  The FSP changes the indicators for determining whether an other-than-temporary impairment on a debt security should be recorded in earnings.  Under current accounting guidance, one of the primary indicators that an unrealized loss should be recognized in earnings is if the company does not have the intent and ability to hold a debt security until recovery of its cost basis.  Under the FSP, the primary indicators that an unrealized loss should be recognized in earnings are whether the company intends to sell the debt security or whether it is more likely than not that the company will be required to sell the debt security prior to recovery of its cost basis.  For  6





debt securities determined to be other-than-temporarily impaired, but which the company does not intend to sell or is not more likely than not going to be required to sell before recovery, credit losses are recognized in earnings, and the remaining unrealized losses are recorded in accumulated other comprehensive income.  For other-than-temporarily impaired debt securities that the company intends to sell or is more likely than not going to be required to sell before recovery, all unrealized losses are recorded in earnings.  Implementation of the FSP, which may affect the accounting for debt securities held in the companys supplemental benefit trust and WMECOs spent nuclear fuel trust, is not expected to have a material effect on the condensed consolidated financial statements.  The company will adopt the FSP by applying its provisions to debt securities held in the supplemental benefit trust as of April 1, 2009 through a cumulative effect adjustment to increase retained earnings and a corresponding adjustment to decrease accumulated other comprehensive income.  Beginning in the second quarter of 2009, for debt securities in the supplemental benefit trust that the company does not intend to sell or does not expect it will more likely than not be required to sell, the company will record credit losses in earnings and other unrealized losses in accumulated other comprehensive income.  Adoption of the FSP for WMECOs spent nuclear fuel trust will not affect shareholders' equity or results of operations due to the regulatory accounting treatment applicable to that trust.  In April 2009, the FASB issued FSP FAS 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly," which is effective prospectively for fair value measurements of assets and liabilities as of June 30, 2009 with early adoption permitted.  The FSP does not change the measurement objective that fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date under current market conditions.  The FSP provides additional guidance on determining whether there has been a significant decrease in the volume and level of activity when compared with normal market activity for an asset or liability and, if so, whether associated transactions or quoted prices are not orderly.  In preparing fair value measurements, reporting entities are required to place more weight on transactions that are orderly than on those that are not orderly.  NU and its subsidiaries will apply the FSP to their fair value measurements of assets and liabilities as of June 30, 2009.  Implementation of the FSP is not expected to have a material effect on the companies condensed consolidated financial statements.  C. Regulatory Accounting The accounting policies of the regulated companies, as defined below, conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."  The transmission and distribution segments of CL&P, PSNH (including its generation business) and WMECO, along with Yankee Gas Service Company's (Yankee Gas) distribution segment (regulated companies), continue to be cost-of-service, rate regulated.  Management believes that the application of SFAS No. 71 to those segments continues to be appropriate.  Management also believes it is probable that NU's regulated companies will recover their respective investments in long-lived assets, including regulatory assets.  All material net regulatory assets are earning an equity return, except for securitized regulatory assets, the majority of deferred benefit costs and regulatory assets offsetting regulated company derivative liabilities, which are not supported by equity.  Amortization and deferrals of regulatory assets/(liabilities) are included on a net basis in amortization expense on the accompanying condensed consolidated statements of income.  Regulatory Assets:  The components of regulatory assets are as follows:  At March 31, 2009At December 31, 2008(Millions of Dollars)NU ConsolidatedNU ConsolidatedDeferred benefit costs$1,127.9$1,140.9Regulatory assets offsetting regulated 
  company derivative liabilities852.5844.2Securitized assets614.6677.4Income taxes, net353.3355.4Unrecovered contractual obligations164.1169.1CL&P undercollections111.375.2Other regulatory assets214.3240.4Totals$3,438.0$3,502.6   7





At March 31, 2009At December 31, 2008(Millions of Dollars)CL&PPSNHWMECOCL&PPSNHWMECODeferred benefit costs$531.9$140.6$112.3$537.7$142.9$113.5Regulatory assets offsetting regulated 
  company derivative liabilities745.5107.0-751.992.1-Securitized assets330.4215.968.3377.8227.672.0Income taxes, net304.119.118.2306.816.120.7Unrecovered contractual obligations128.9-35.1132.6-36.5CL&P undercollections111.3--75.2--WMECO recoverable nuclear costs--4.0--5.0Other regulatory assets73.665.921.692.171.220.7Totals$2,225.7$548.5$259.5$2,274.1$549.9$268.4  Additionally, the regulated companies had $70.6 million ($62.8 million for PSNH, $6.6 million for CL&P, and $1.2 million for WMECO) and $68.3 million ($62.7 million for PSNH and $5.6 million for CL&P) of regulatory costs at March 31, 2009 and December 31, 2008, respectively, which were included in deferred debits and other assets - other on the accompanying condensed consolidated balance sheets.  These amounts represent incurred costs that have not yet been approved for recovery by the applicable regulatory agency.  Of these amounts, $62.4 million and $62.7 million at March 31, 2009 and December 31, 2008, respectively, related to costs incurred at PSNH for the December 2008 storm restorations that met the New Hampshire Public Utilities Commission (NHPUC) specified criteria for deferral to a major storm cost reserve.  Management believes these costs are recoverable in future cost-of-service regulated rates.  Included in NU's other regulatory assets are the regulatory assets associated with the implementation of FASB Interpretation No. (FIN) 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $43.3 million ($23.8 million for CL&P, $14.1 million for PSNH, and $2.8 million for WMECO) at March 31, 2009 and $42.3 million ($23.1 million for CL&P, $13.9 million for PSNH, and $2.8 million for WMECO) at December 31, 2008.  Of these amounts, $12.1 million and $12 million, respectively, related to PSNH have been approved for future recovery.  Management believes that recovery of the remaining FIN 47 regulatory assets is probable.  Regulatory Liabilities:  The components of regulatory liabilities are as follows:  At March 31, 2009At December 31, 2008(Millions of Dollars)NU ConsolidatedNU ConsolidatedCost of removal$222.3$226.0Regulatory liabilities offsetting 
  regulated company derivative assets107.9137.8CL&P overcollections54.469.5CL&P AFUDC transmission incentive47.947.6PSNH deferred ES revenue, net41.133.0Pension and PBOP liabilities - Yankee 
  Gas acquisition16.917.6Overrecovered gas costs23.116.9Other regulatory liabilities41.944.1Totals$555.5$592.5  At March 31, 2009At December 31, 2008(Millions of Dollars)CL&PPSNHWMECOCL&PPSNHWMECORegulatory liabilities offsetting 
  regulated company derivative assets$105.2$1.8$-$131.3$4.6$-Cost of removal89.263.618.491.264.719.2CL&P overcollections54.4--69.5--CL&P AFUDC transmission incentive47.9--47.6--PSNH deferred ES revenue, net-41.1--33.0-WMECO transition charge overcollections--3.6--5.7WMECO pension/PBOP tracker--0.8--2.0Other regulatory liabilities25.47.73.823.99.12.9Totals$322.1$114.2$26.6$363.5$111.4$29.8   8





D. Allowance for Funds Used During Construction Allowance for funds used during construction (AFUDC) is included in the cost of the regulated companies' utility plant and represents the cost of borrowed and equity funds used to finance construction.  The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense, and the AFUDC related to equity funds is recorded as other income, net on the accompanying condensed consolidated statements of income.  For the Three Months EndedMarch 31, 2009March 31, 2008(Millions of Dollars, except percentages)NU ConsolidatedNU ConsolidatedBorrowed funds$2.1$4.7Equity funds0.98.3Totals$3.0$13.0Average AFUDC rates5.2%8.2%  For the Three Months EndedMarch 31, 2009March 31, 2008(Millions of Dollars, except percentages)CL&PPSNHWMECOCL&PPSNHWMECOBorrowed funds$0.9$0.9$0.1$3.4$0.9$0.2Equity funds-0.9-6.61.40.3Totals$0.9$1.8$0.1$10.0$2.3$0.5Average AFUDC rates3.2%8.1%3.8%8.5%8.1%7.9%  The regulated companies' average AFUDC rate is based on a Federal Energy Regulatory Commission (FERC) prescribed formula that produces an average rate using the cost of a company's short-term financings as well as a company's capitalization (preferred stock, long-term debt and common equity).  The average rate is applied to average eligible construction work in progress (CWIP) amounts to calculate AFUDC.  AFUDC is recorded on 100 percent of CL&P's and WMECO's CWIP for their New England East-West Solutions (NEEWS) projects, all of which is being reserved as a regulatory liability to reflect current rate base recovery for 100 percent of the CWIP as a result of FERC-approved transmission incentives.  E. Other Income, Net The pre-tax components of other income/(loss) items are as follows:  NU ConsolidatedFor the Three Months Ended(Millions of Dollars)March 31, 2009March 31, 2008Other Income:Interest income$0.8$-Investment income1.81.9AFUDC - equity funds0.98.3Energy Independence Act incentives3.65.5Conservation and load management incentives0.10.3Other0.30.2Total Other Income7.516.2Other Loss:Investment write-downs(3.2)(2.6)Rental expense(0.1)-Total Other Loss(3.3)(2.6)Total Other Income, Net$4.2$13.6  CL&PFor the Three Months Ended(Millions of Dollars)March 31, 2009March 31, 2008Other Income:Investment income$1.1$1.4AFUDC - equity funds-6.6Energy Independence Act incentives3.65.5Conservation and load management incentives-0.2Other0.20.2Total Other Income4.913.9Investment write-downs(2.2)(1.8)Total Other Income, Net$2.7$12.1  9





PSNHFor the Three Months Ended(Millions of Dollars)March 31, 2009March 31, 2008Other Income:Interest income$0.8$-Investment income0.20.3AFUDC - equity funds0.91.4Total Other Income1.91.7Investment write-downs(0.5)(0.4)Total Other Income, Net$1.4$1.3  WMECOFor the Three Months Ended(Millions of Dollars)March 31, 2009March 31, 2008Other Income:Investment income$0.2$0.2AFUDC - equity funds-0.3Conservation and load management incentives0.10.1Total Other Income0.30.6Investment write-downs(0.5)(0.4)Total Other (Loss)/Income, Net$(0.2)$0.2  Investment income includes equity in earnings of regional nuclear generating and transmission companies of $0.5 million and $0.7 million for NU consolidated ($0.1 million in both periods for CL&P and de minimus amounts for PSNH and WMECO) for the three months ended March 31, 2009 and 2008, respectively.  Equity in earnings relates to the company's consolidated investments, including CL&P, PSNH and WMECOs investments, in Connecticut Yankee Atomic Power Company (CYAPC), Maine Yankee Atomic Power Company, and Yankee Atomic Electric Company and NUs investments in two regional transmission companies.  F. Special Deposits and Counterparty Deposits To the extent NU Enterprises, Inc (NU Enterprises), a wholly owned subsidiary of NU, through its wholly owned subsidiary Select Energy, Inc. (Select Energy), requires collateral from counterparties, or the counterparties require collateral from Select Energy, cash is held on deposit by Select Energy or with unaffiliated counterparties and brokerage firms as a part of the total collateral required based on Select Energy's position in transactions with the counterparty.  Select Energy's right to use cash collateral is determined by the terms of the related agreements.  Key factors affecting the unrestricted status of a portion of this cash collateral include the financial standing of Select Energy and of NU as its credit supporter.  NU and its subsidiaries record special deposits and counterparty deposits in accordance with FSP FIN 39-1, "Amendment of FASB Interpretation No. 39," which requires NU to net collateral amounts posted under a master netting agreement if the related derivatives are recorded in a net position.  At March 31, 2009, CL&P had $1 million in cash collateral deposited with counterparties.  At March 31, 2009 and December 31, 2008, NU and its subsidiaries, including CL&P, PSNH and WMECO, had no special deposits or counterparty collateral posted under master netting agreements netted against the fair value of derivatives.  Special deposits paid by Select Energy to unaffiliated counterparties and brokerage firms were not subject to master netting agreements and totaled $35.7 million and $26.3 million at March 31, 2009 and December 31, 2008, respectively.  These amounts are recorded as current assets and are included in prepayments and other on the accompanying condensed consolidated balance sheets.  There were no counterparty deposits for Select Energy as of March 31, 2009 and December 31, 2008.  NU consolidated, CL&P, PSNH and WMECO have established credit policies regarding counterparties to minimize overall credit risk.  These policies require an evaluation of potential counterparties, financial condition, collateral requirements and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  These evaluations result in established credit limits prior to entering into a contract.  At March 31, 2009 and December 31, 2008, there were no counterparty deposits for these companies.  G. Income Taxes Tax Positions:  In March 2009, CL&P and Yankee Gas reached a settlement with state tax authorities that closed certain state income tax years 1997 through 2000.  The settlement resulted in CL&P and Yankee Gas making payments of approximately $4 million and $1 million, respectively, and increased pre-tax income by approximately $3 million on an NU consolidated basis (approximately $3 million at CL&P).  The settlement did not have a significant impact on NU, CL&P or Yankee Gas's first quarter income tax expense and is not expected to have a significant impact on NU, CL&P or Yankee Gas's 2009 income tax expense or earnings.   10





H. Other Taxes Certain excise taxes levied by state or local governments are collected by CL&P and Yankee Gas from their respective customers.  These excise taxes are accounted for on a gross basis with collections in revenues and payments in expenses.  For the three months ended March 31, 2009 and 2008, gross receipts taxes, franchise taxes and other excise taxes for NU consolidated of $39 million and $31 million, respectively, ($30.9 million and $23.7 million, respectively, for CL&P) were included in operating revenues and taxes other than income taxes on the accompanying condensed consolidated statements of income.  Certain sales taxes are also collected by CL&P and Yankee Gas from their respective customers as agents for state and local governments and are recorded on a net basis with no impact on the accompanying condensed consolidated statements of income.  2. DERIVATIVE INSTRUMENTS (NU, NU Enterprises, CL&P, PSNH, Yankee Gas) On January 1, 2009, NU and its subsidiaries, including CL&P, PSNH and WMECO, adopted SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133," which establishes disclosure requirements for derivative instruments and hedging activities.  SFAS No. 161 requires disclosure, presented below, of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect an entitys financial position, financial performance and cash flows.  CL&P, PSNH, WMECO and Yankee Gas are exposed to the volatility of the prices of energy and energy related products in procuring supply for their customers.  The costs associated with supplying energy to customers are recoverable through customer rates.  The company manages the risks associated with the price volatility of energy and energy related products through the use of derivative contracts, many of which are accounted for as normal purchases and sales, and the use of non-derivative contracts.  CL&P mitigates the risks associated with the price volatility of energy and energy-related products through the use of standard or last resort service contracts, which fix the price of electricity purchased for customers for periods of time ranging from three months to three years and are accounted for under the normal purchases and sales exception.  CL&P has entered into derivatives, including financial transmission rights contracts (FTRs) and bilateral basis swaps, to manage the risk of congestion costs associated with its standard offer and last resort service contracts.  As required by regulation, CL&P has also entered into derivative and non-derivative contracts for the purchase of energy and energy-related products and contracts related to capacity.  While the risks managed by these contracts are regional congestion costs and capacity price risks that are not specific to CL&P, Connecticut's electric distribution companies, including CL&P, are required to enter into these contracts.  The derivative contracts not accounted for under the normal purchases and sales exception are accounted for at fair value, and because management believes any costs or benefits from these contracts are recoverable from or refunded to CL&P's customers, any changes in fair value are recorded as regulatory assets and liabilities.  WMECO mitigates the risks associated with the volatility of the prices of energy and energy-related products in procuring energy supply for its customers through the use of default service contracts, which fix the price of electricity purchased for customers for periods of time ranging from three months to three years and are accounted for under the normal purchases and sales exception.  PSNH mitigates the risks associated with the volatility of energy prices in procuring energy supply for its customers through its generation facilities and the use of derivative contracts, including energy forward contracts, options and FTRs.  PSNH enters into these contracts in order to stabilize electricity rates for customers.  The derivative contracts not accounted for under the normal purchases and sales exception are accounted for at fair value, and because management believes any costs or benefits from these contracts are recoverable from or refunded to PSNH's customers, any changes in fair value are recorded as regulatory assets and liabilities.  Yankee Gas mitigates the risks associated with supply availability and volatility of natural gas prices through the use of storage facilities and long-term agreements to purchase gas supply for customers that include non-derivative contracts and contracts that are accounted for as normal purchases.  Yankee Gas also manages price risk through the use of options contracts.  The derivative contracts not accounted for under the normal purchases and sales exception are accounted for at fair value, and because management believes any costs or benefits from these contracts are recoverable from or refundable to Yankee Gas' customers, any changes in fair value are recorded as regulatory assets and liabilities.  NU Enterprises, through Select Energy, has one remaining fixed price forward sales contract that was entered into as part of its wholesale energy marketing business.  NU Enterprises mitigates the price risk associated with this contract through the use of forward purchase contracts.  NU Enterprises derivative contracts are accounted for at fair value, and changes in their fair values are recorded in earnings.  The company is also exposed to interest rate risk associated with its long-term debt.  From time to time, the company enters into forward starting interest rate swaps, accounted for as cash flow hedges, to mitigate the risk of changes in interest rates when it expects to issue long-term debt.  The company has also entered into an interest rate swap on fixed rate long-term debt in order to manage the balance of fixed and floating rate debt.  The interest rate swap mitigating the interest rate risk associated with the fixed rate long-term debt is accounted for as a fair value hedge.  11





Derivative contracts that meet the definition of and are designated as normal purchases or normal sales are recognized in revenues or expenses, as applicable, as electricity or gas is delivered.  Derivative contracts that are not designated as hedging instruments or as normal purchases or normal sales are recorded at fair value as current or long-term derivative assets or liabilities.  Changes in fair values of NU Enterprises' derivatives are included in earnings.  For the regulated companies, including CL&P, PSNH and Yankee Gas, regulatory assets or liabilities are recorded for the changes in fair values of derivatives, as these contracts are part of stranded costs or are current regulated operating costs, and management believes that these costs will continue to be recovered from or refunded to customers in cost-of-service, regulated rates.  The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported net as derivative assets or derivative liabilities in the accompanying condensed consolidated balance sheets.  The following tables present the gross fair values of contracts and the net amounts recorded as current or long-term derivative assets or liabilities, by primary underlying risk exposures or purpose:  At March 31, 2009NU Consolidated(Millions of Dollars)Gross
AssetGross
LiabilityNet
Amount
Recorded as
Derivative
AssetGross
AssetGross
LiabilityNet 
Amount
Recorded as
Derivative
LiabilityDerivatives not designated as hedging 
instruments under SFAS No. 133NU Enterprises:Commodity sales contract and related
   price and supply risk management:Current$-$-$-$6.2$(13.1)$(6.9)Long-Term---13.1(55.4)(42.3)Regulated Companies:CL&P commodity and capacity contracts
   required by regulation:Current0.1(2.9)(2.8)(1)-(7.9)(7.9)Long-Term259.4(48.1)211.3(1)-(835.3)(835.3)CL&P, PSNH and Yankee Gas commodity
   price and supply risk management:Current7.1-7.1-(92.3)(92.3)Long-Term2.5-2.5-(20.4)(20.4)Derivatives designated as hedging
  instruments under SFAS No. 133Interest rate risk management:Current(2)4.4-4.4---Long-Term15.5-15.5---  (1) Fair value amounts of $(2.9) million current and $105.7 million long-term that are subject to a sharing agreement are recorded in derivative assets.  (2) Amount does not include interest receivable of $3.7 million as of March 31, 2009 recorded in prepayments and other on the accompanying condensed consolidated balance sheet.  12





At March 31, 2009CL&P(Millions of Dollars)Gross
AssetGross
LiabilityNet
Amount
Recorded as
Derivative
AssetsGross
AssetGross
LiabilityNet 
Amount
Recorded as
Derivative
LiabilityDerivatives not designated as hedging 
  instruments under SFAS No. 133Commodity and capacity contracts
  required by regulation:Current$0.1$(2.9)$(2.8)(1)$-$(7.9)$(7.9)Long-Term259.4(48.1)211.3(1)-(835.3)(835.3)Commodity price and supply risk 
  management:Current6.9-6.9-(5.5)(5.5)Long-Term------  (1) Fair value amounts of $(2.9) million current and $105.7 million long-term that are subject to a sharing agreement are recorded in derivative assets.  At March 31, 2009PSNH(Millions of Dollars)Gross
AssetGross
LiabilityNet
Amount
Recorded as
Derivative
AssetsGross
AssetGross
LiabilityNet 
Amount
Recorded as
Derivative
LiabilityDerivatives not designated as hedging 
  instruments under SFAS No. 133Commodity price and supply  risk 
  management:Current$0.2$-$0.2$-$(86.7)$(86.7)Long-Term1.6-1.6-(20.4)(20.4)  WMECO does not have derivatives that are recorded at fair value on the accompanying condensed consolidated balance sheets.  For further information on the fair value of derivative contracts, see Note 3, "Fair Value Measurements," to the condensed consolidated financial statements.  The following provides additional information about the derivatives included in the tables above, including volumes and cash flow information.  Derivatives not designated as hedging instruments under SFAS No. 133 NU Enterprises' energy sales contract and related price risk management:At March 31, 2009, NU Enterprises had approximately 0.2 million megawatt-hours (MWH) remaining under its wholesale sales contract expiring in 2013 to sell electricity to the New York Municipal Power Agency (NYMPA) (an agency that is comprised of municipalities), net of sourcing contracts to purchase electricity with delivery dates through 2013.  These contracts affect cash flows as electricity is purchased and delivered.  CL&P energy and capacity contracts required by regulation:  CL&P has contracts with two independent power producers (IPPs) to purchase electricity monthly in amounts aggregating approximately 1.5 million MWH per year through March 2015 under one of these contracts and 0.1 million MWH per year through December 2020 under the second contract.  CL&P also has two capacity-related contracts for differences (CfDs) to increase energy supply in Connecticut relating to two generating projects to be built or modified.  The total capacity of these CfDs and two additional CfDs of The United Illuminating Company (UI) is expected to be approximately 787 MW.  These four contracts obligate the utilities to pay/receive monthly the difference between a set capacity price and the forward capacity market price that the projects receive in the New England Independent System Operator (ISO-NE) capacity markets for periods of up to 15 years beginning in 2009.  CL&P has an agreement with UI, which is also accounted for as a derivative, under which it will share the costs and benefits of the four CfDs, with 80 percent allocated to CL&P and 20 percent to UI.  CL&P, PSNH and Yankee Gas energy and natural gas price risk management:At March 31, 2009, CL&P had 1.8 million MWH and 1.3 million MWH remaining under FTRs and bilateral basis swaps, respectively, that expire in 2009 and require monthly payments or receipts.   13





PSNH has electricity procurement contracts with delivery dates through 2011 to purchase an aggregate amount of 2.9 million MWH of power that is used to serve customer load and manage price risk of its electricity delivery service obligations.  These contracts are settled monthly.  PSNH also has two energy call options that it received in exchange for assigning its transmission rights in a direct current transmission line.  The options give PSNH the right to purchase monthly 1 million MWH of electricity through December 2010.  In addition, PSNH has entered into FTRs to manage the risk of congestion costs associated with its electricity delivery service.  At March 31, 2009, there were 1 million MWH remaining under FTRs that expire in 2009 and require monthly payments or receipts.  The purpose of the PSNH derivative contracts is to provide stable rates for customers by mitigating price uncertainties associated with the New England spot market.  Yankee Gas has two peaking supply option contracts to purchase up to 17 thousand MMBtu of natural gas on up to 20 days per season to manage natural gas supply price risk related to winter load obligations.  One contract for 3 thousand MMBtu expires on October 31, 2009 and the other contract for 14 thousand MMBtu expires on April 1, 2012.  Demand fees on these contracts are payable annually.  The following table presents the realized and unrealized gains/(losses) associated with derivative contracts not designated as hedging instruments under SFAS No. 133 for the three months ended March 31, 2009 (millions of dollars):  Derivatives Not Designated
as Hedging Instruments
under SFAS No. 133Location of Gain or Loss
Recognized on DerivativeAmount of Gain/(Loss)
Recognized on DerivativeNU Enterprises:Energy sales contract and energy price 
  risk managementFuel, purchased and net 
  interchange power$5.5Regulated Companies:CL&P energy and capacity 
  contracts required by regulationRegulatory assets/liabilities(11.1)Commodity price and supply risk
  management:CL&PRegulatory assets/liabilities(5.9)PSNHRegulatory assets/liabilities(42.5)Yankee GasRegulatory assets/liabilities(0.9)  For the regulated companies, monthly settlement amounts are recorded as receivables or payables and as revenues or purchased power.  Regulatory assets/liabilities are established through amortization of regulatory assets/liabilities, net, with no impact to net income.  Derivatives designated as hedging instruments under SFAS No. 133 Interest Rate Risk Management:To manage the interest rate risk characteristics of the company's fixed rate long-term debt, NU parent has a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed rate senior notes maturing on April 1, 2012.  This interest rate swap qualified and was designated as a fair value hedge and requires semi-annual payments/receipts.  Under fair value hedge accounting, the changes in fair value of the swap and the interest component of the hedged long-term debt instrument are recorded in interest expense.  There was no ineffectiveness recorded for the three months ended March 31, 2009.  The cumulative changes in fair values of the swap and the long-term debt are recorded as a derivative and an adjustment to long-term debt.  Interest receivable is recorded as a reduction of interest expense and is included in prepayments and other.  For the three months ended March 31, 2009, the realized and unrealized gains/(losses) incurred on the swap and hedged debt and interest expense recorded in earnings were as follows (millions of dollars):  Income Statement ClassificationSwapHedged DebtChange in fair value$0.5$(0.5)Interest recorded in earnings-1.4  There were no cash flow hedges outstanding as of March 31, 2009 or during the three months ended March 31, 2009 and no ineffectiveness was recorded for that period.  From time to time, NU and its subsidiaries, including CL&P, PSNH and WMECO, enter into forward starting interest rate swap agreements on proposed debt issuances that qualify and are designated as cash flow hedges.  Cash flow hedges are recorded at fair value, and the changes in the fair value of the effective portion of those contracts are recognized in accumulated other comprehensive income.  Cash flow hedges impact net income when the hedged items affect earnings, when hedge ineffectiveness is measured and recorded, or when the forecasted transaction being hedged is improbable of occurring.  When a cash flow hedge is terminated, the settlement amount is recorded in accumulated other comprehensive income and is amortized into earnings over the term of the debt.   14





For the three months ended March 31, 2009, pre-tax gains/(losses) amortized from accumulated other comprehensive income into interest expense were as follows (millions of dollars):  CL&P$(0.2)PSNH-WMECO-Other0.1NU Consolidated$(0.1)  For further information, see Note 6, "Comprehensive Income," to the condensed consolidated financial statements.  Credit Risk Certain derivative contracts that are accounted for at fair value, including PSNH's electricity procurement contracts, CL&P's bilateral agreements and NU Enterprises' electricity sourcing contracts, contain credit risk contingent features.  These features require these companies, or in NU Enterprises' case, NU, to maintain investment grade credit ratings from the major rating agencies and to post cash or standby letters of credit (LOCs) as collateral for contracts in a net liability position over specified credit limits.  NU provides standby LOCs under its revolving credit agreement for its subsidiaries to post with counterparties.  The following summarizes the fair value of derivative contracts that are in a liability position and subject to credit risk contingent features and the fair value of cash collateral and standby LOCs posted with counterparties as of March 31, 2009 (millions of dollars):  Fair value
subject to
credit risk
contingent
featuresCash
collateral
postedStandby
LOCs
postedCL&P$(1.0)$1.0$-PSNH(106.7)-91.0NU Enterprises(37.8)35.7-NU Consolidated$(145.5)$36.7$91.0  Additional collateral is required to be posted by NU Enterprises, CL&P or PSNH, respectively, if NU parent's, CL&P's or PSNH's respective credit ratings are downgraded below investment grade.  As of March 31, 2009, no additional cash collateral would be required to be posted if credit ratings were downgraded below investment grade.  However, if PSNH's or NU parent's senior unsecured debt were downgraded to below investment grade, additional standby LOCs in the amount of $26.5 million and $13.4 million would be required to be posted for PSNH and Select Energy, respectively.  For further information, see Note 1F, "Summary of Significant Accounting Policies - Special Deposits and Counterparty Deposits," to the condensed consolidated financial statements.  3. FAIR VALUE MEASUREMENTS (All Companies) Items Measured at Fair Value on a Nonrecurring Basis:On January 1, 2009, NU and its subsidiaries, including CL&P, PSNH and WMECO, adopted SFAS No. 157, "Fair Value Measurements," for nonrecurring fair value measurements of nonfinancial assets and liabilities, including asset retirement obligations (AROs) and goodwill and other impairment analyses.  We adopted SFAS No. 157 for fair value measurements of financial assets and liabilities effective January 1, 2008.  Implementation of SFAS No. 157 for nonfinancial assets and liabilities did not affect the accompanying condensed consolidated financial statements.  Application of SFAS No. 157 to Yankee Gas goodwill, which is tested for impairment as of October 1st of each year, is not expected to have a material effect on the companys financial position or results of operations.  Items Measured at Fair Value on a Recurring Basis:The company's assets and liabilities recorded at fair value on a recurring basis have been categorized based upon the fair value hierarchy in accordance with SFAS No. 157.   15





The following tables present the amounts of assets and liabilities carried at fair value by the level in which they are classified within the SFAS No. 157 valuation hierarchy:  At March 31, 2009(Millions of Dollars)Total NUCL&PPSNHWMECONU
EnterprisesYankee GasNU ParentDerivative Assets:Level 1$-$-$-$-$-$-$-Level 219.9-----19.9Level 3218.1215.41.8--0.9-Total$238.0$215.4$1.8$-$-$0.9$19.9Derivative Liabilities:Level 1$-$-$-$-$-$-$-Level 2(106.7)-(106.7)----Level 3(898.4)(848.7)(0.4)-(49.2)(0.1)-Total$(1,005.1)$(848.7)$(107.1)$-$(49.2)$(0.1)$-Marketable Securities:Level 1$51.4$-$-$21.4$-$-$30.0Level 255.2--34.6--20.6Level 3-------Total$106.6$-$-$56.0$-$-$50.6  At December 31, 2008(Millions of Dollars)Total NUCL&PPSNHWMECONU
EnterprisesYankee GasNU ParentDerivative Assets:Level 1$-$-$-$-$-$-$-Level 220.8-----20.8Level 3252.4245.84.7--1.9-Total$273.2$245.8$4.7$-$-$1.9$20.8Derivative Liabilities:Level 1$-$-$-$-$-$-$-Level 2(91.7)-(91.7)----Level 3(921.6)(856.9)(0.6)-(63.9)(0.2)-Total$(1,013.3)$(856.9)$(92.3)$-$(63.9)$(0.2)$-Marketable Securities:Level 1$42.1$-$-$10.3$-$-$31.8Level 267.1--45.4--21.7Level 3-------Total$109.2$-$-$55.7$-$-$53.5  Not included in the tables above are $393.6 million and $81.6 million of cash equivalents held by NU parent at March 31, 2009 and December 31, 2008, respectively, which are included in cash and cash equivalents on the accompanying condensed consolidated balance sheets and are classified as Level 1 in the fair value hierarchy.  The following tables present changes for the three months ended March 31, 2009 and 2008 in the Level 3 category of assets and liabilities measured at fair value on a recurring basis.  This category includes derivative assets and liabilities, which are presented net.  The company classifies assets and liabilities in Level 3 of the fair value hierarchy when there is reliance on at least one significant unobservable input to the valuation model.  In addition to these unobservable inputs, the valuation models for Level 3 assets and liabilities typically also rely on a number of inputs that are observable either directly or indirectly.  Thus, the gains and losses presented below include changes in fair value that are attributable to both observable and unobservable inputs.  There were no transfers into or out of Level 3 assets and liabilities for the three months ended March 31, 2009 and 2008.  16





For the Three Months Ended March 31, 2009(Millions of Dollars)Total NUCL&PPSNHNU
EnterprisesYankee 
GasDerivatives, Net:Fair value at January 1, 2009$(669.2)$(611.1)$4.1$(63.9)$1.7Net realized/unrealized gains/(losses) 
  included in:Earnings (1)5.5--5.5-Regulatory assets/liabilities(20.6)(17.0)(2.7)-(0.9)Purchases, issuances and settlements4.0(5.2)-9.2-Fair value at March 31, 2009$(680.3)$(633.3)$1.4$(49.2)$0.8Quarterly change in unrealized gains
  included in earnings relating to items
  held at March 31, 2009$5.3$-$-$5.3$-  For the Three Months Ended March 31, 2008(Millions of Dollars)Total NUCL&PPSNHNU
EnterprisesYankee 
GasDerivatives, Net:Fair value at January 1, 2008 (2)$(511.1)$(426.9)$15.7$(100.1)$0.2Net realized/unrealized gains/(losses) 
  included in:Earnings (1)3.7--3.7-Regulatory assets/liabilities16.89.87.1-(0.1)Purchases, issuances and settlements2.1(13.2)-15.3-Fair value at March 31, 2008$(488.5)$(430.3)$22.8$(81.1)$0.1Quarterly change in unrealized gains 
  included in earnings relating to items 
  held at March 31, 2008$0.8$-$-$0.8$-  (1) Realized and unrealized gains and losses on derivatives included in earnings relate to the remaining Select Energy wholesale marketing contracts and are reported in fuel, purchased and net interchange power on the accompanying condensed consolidated statements of income.  (2) Amounts as of January 1, 2008 reflect fair values after initial adoption of SFAS No. 157.  As a result of implementing SFAS No. 157, the company recorded an increase to derivative liabilities and a pre-tax charge to earnings of $6.1 million as of January 1, 2008 related to NU Enterprises' remaining derivative contracts.  The company also recorded changes in fair value of CL&P's CfD and IPP contracts, resulting in increases to CL&P's derivative liabilities of approximately $590 million, with an offset to regulatory assets and a decrease to CL&P's derivative assets of approximately $30 million with an offset to regulatory liabilities.  4. PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (All Companies) NU sponsors a single uniform noncontributory defined benefit retirement plan (Pension Plan), which is subject to the provisions of the Employee Retirement Income Security Act (ERISA) and covers substantially all regular employees of NU and its subsidiaries hired before 2006 (or as negotiated, for bargaining employees) and also provides certain retiree health care benefits, primarily medical and dental, and life insurance benefits through a post-retirement benefits other than pension (PBOP) Plan.  In addition, NU maintains a Supplemental Executive Retirement Plan (SERP), which provides benefits to eligible participants who are officers of NU or its subsidiaries.  This plan primarily provides benefits that would have been provided to these employees under the Pension Plan if certain Internal Revenue Code limitations were not imposed.   17





The components of net periodic expense/(income) for the Pension Plan, PBOP Plan and SERP for the three months ended March 31, 2009 and 2008 are as follows:  For the Three Months Ended March 31,NU ConsolidatedPension BenefitsPBOP BenefitsSERP Benefits(Millions of Dollars)200920082009200820092008Service cost$11.3$10.7$1.8$1.8$0.2$0.2Interest cost38.536.27.37.10.60.5Expected return on plan assets(47.4)(50.1)(5.1)(5.3)--Net transition obligation cost0.10.12.92.9--Prior service cost/(credit)2.52.4(0.1)(0.1)--Actuarial loss5.11.42.52.60.10.1Total - net periodic expense$10.1$0.7$9.3$9.0$0.9$0.8CL&P - net periodic (income)/expense$(1.4)$(5.4)$4.0$3.9$0.1$0.1PSNH - net periodic expense$5.8$4.5$1.8$1.7$0.1$0.1WMECO - net periodic (income)/expense$(0.7)$(1.6)$0.7$0.7$*$*  *A de minimus amount of SERP expense was recorded for WMECO.  Not included in the pension expense/(income) amounts above for CL&P, PSNH and WMECO are pension related intercompany allocations totaling $3.7 million, $0.8 million and $0.6 million, respectively, for the three months ended March 31, 2009.  These amounts were $2.1 million, $0.4 million and $0.3 million, respectively, for the three months ended March 31, 2008.  Not included in the PBOP amounts for CL&P, PSNH and WMECO are related intercompany allocations of $1.7 million, $0.4 million and $0.3 million, respectively, for both the three months ended March 31, 2009 and 2008.  Not included in the SERP amounts for CL&P, PSNH and WMECO are related intercompany allocations of $0.5 million, $0.1 million and $0.1 million, respectively, for the three months ended March 31, 2009.  These amounts were $0.4 million, $0.1 million and a de minimus amount, respectively, for the three months ended March 31, 2008.  A portion of these pension amounts is capitalized related to current employees who are working on capital projects.  Amounts capitalized on an NU consolidated basis were approximately $1.5 million and $1.4 million for the three months ended March 31, 2009 and 2008, respectively.  The amount for the three months ended March 31, 2008 offsets capital costs, as pension income was recorded for certain of NU subsidiaries.  For CL&P, PSNH and WMECO, amounts capitalized, including intercompany allocations, were a de minimus amount, $1.4 million and $0.2 million, respectively, for the three months ended March 31, 2009 and $2.2 million, $1.1 million and $0.6 million, respectively, for the three months ended March 31, 2008.  The amounts for CL&P and WMECO offset capital costs, as pension income was recorded.  5. COMMITMENTS AND CONTINGENCIES  A. Regulatory Developments and Rate Matters (CL&P, PSNH, WMECO)  Connecticut:  CTA and SBC Reconciliation:  On March 31, 2009, CL&P filed with the Connecticut Department of Public Utility Control (DPUC) its 2008 Competitive Transition Assessment (CTA) and Systems Benefit Charge (SBC) reconciliation, which compared CTA and SBC revenues to revenue requirements.  For the 12 months ended December 31, 2008, total CTA revenues exceeded CTA revenue requirements by $84.9 million, which has been recorded as a decrease to the CTA regulatory asset on the accompanying condensed consolidated balance sheet.  For the 12 months ended December 31, 2008, the SBC revenues exceeded SBC cost of service by $2.5 million, which has been recorded as a decrease to the SBC regulatory asset on the accompanying condensed consolidated balance sheet.  Management expects a decision in this docket from the DPUC by the end of 2009 and does not expect the outcome to have a material adverse impact on CL&Ps net income or financial position.  FMCC Filing:  On February 6, 2009, CL&P filed with the DPUC its semi-annual Federally Mandated Congestion Charge (FMCC) filing, which reconciled actual FMCC revenues and charges and generation service charge revenues and expenses, for the period July 1, 2008 through December 31, 2008, and also included the previously filed revenues and expenses for the January 1, 2008 through June 30, 2008 period.  The filing identified an underrecovery for the full year totaling approximately $31.9 million, which has been recorded as a regulatory asset on the accompanying condensed consolidated balance sheets.  The DPUC held a hearing on this filing on April 9, 2009 with a final decision expected in the second quarter of 2009.  Management does not expect the outcome of the DPUC's review of this filing to have a material adverse impact on CL&P's net income, financial position or cash flows.   18





C2 Prudency Audit:  Pursuant to the decision in CL&P's 2007 rate case, the DPUC has hired a consulting firm to perform a prudency audit of certain costs incurred in the implementation of a new customer service system (C2) at CL&P.  The audit began on December 1, 2008 and is ongoing.  The DPUC intends to open a docket to review the findings of the audit after completion.  Management continues to believe that its C2 expenses were prudent and will be recovered in rates.  Management does not expect the outcome of the DPUC's review of this audit to have a material adverse impact on CL&P's net income, financial position or cash flows.  New Hampshire:  ES and SCRC Reconciliation and Rates:On an annual basis, PSNH files with the NHPUC a default energy service charge/stranded cost recovery charge (ES/SCRC) reconciliation filing for the preceding year.On May 1, 2009, PSNH filed its 2008 ES/SCRC reconciliation with the NHPUC, whose evaluation includes a prudence review of PSNH's generation activities.  During 2008, ES revenues exceeded ES costs by $20.7 million and SCRC costs exceeded SCRC revenues by $6.4 million resulting in an ES regulatory liability for refunds to customers, and a SCRC regulatory asset for costs that will be recovered from customers.  Management does not expect the outcome of the NHPUC review to have a material adverse impact on PSNH's net income or financial position.  Massachusetts:  Transition Cost Reconciliation:  On July 18, 2008, WMECO filed its 2007 transition cost (TC) reconciliation with the Massachusetts Department of Public Utilities (DPU), which compared TC revenue and revenue requirements.  For the twelve months ended December 31, 2007, total TC revenues along with carrying charges exceeded TC revenue requirements by $2.6 million, which has been recorded as a regulatory liability on the accompanying consolidated balance sheets.  A public hearing and procedural conference was held on November 20, 2008.  On December 22, 2008, the Massachusetts Attorney General filed testimony on two topics: the deferred return and carrying charges on the Capital Project Scheduling List; and the recovery of WMECO's share of Northeast Nuclear Energy Company pension/PBOP costs.  WMECO filed rebuttal testimony on December 30, 2008.  A hearing was held on January 29, 2009.  There is no timeline for a DPU decision.  Management does not expect the outcome of the DPU's review of this filing to have a material adverse impact on WMECO's net income, financial position or cash flows.  B. Environmental Matters (HWP) Holyoke Water Power Company (HWP) is a subsidiary of NU that remains in the process of evaluating additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with a manufactured gas plant (MGP) site, which it sold to Holyoke Gas and Electric (HG&E), a municipal electric utility, in 1902.  HWP is at least partially responsible for this site, and has already conducted substantial investigative and remediation activities.  HWP first established a reserve for this site in 1994.  A pre-tax charge of approximately $3 million was recorded in 2008 to reflect the estimated cost of further tar delineation and site characterization studies, as well as certain remediation costs that are considered to be probable and estimable as of December 31, 2008.  For the three months ended March 31, 2009, no such charges were recognized.  The cumulative expense recorded to this reserve through March 31, 2009 was approximately $15.9 million, of which $14.2 million had been spent, leaving approximately $1.7 million in the reserve as of March 31, 2009.  The Massachusetts Department of Environmental Protection (MA DEP) issued a letter on April 3, 2008 to HWP and HG&E, which share responsibility for the site, 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.  This letter represents guidance from the MA DEP, rather than mandates.  HWP has developed and begun to implement plans for 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.  At this time, management believes that the $1.7 million remaining in the reserve is at the low end of a range of probable and estimable costs of approximately $1.7 million to $2.4 million and will be sufficient for HWP to conduct the additional tar delineation and site characterization studies, evaluate its approach to this matter and conduct certain soft tar remediation.  The additional studies are expected to occur throughout 2009.  There are many outcomes that could affect management's 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, management 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.   19





C. Guarantees and Indemnifications (All Companies) NU parent provides credit assurances on behalf of its subsidiaries, including CL&P, PSNH and WMECO, in the form of guarantees and LOCs in the normal course of business.  NU has also provided guarantees and various indemnifications on behalf of external parties as a result of the sales of Select Energy Services, Inc. (SESI), NU Enterprises' retail marketing business and its competitive generation business.  The following table summarizes NU and its subsidiaries' maximum exposure at March 31, 2009, in accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," and expiration dates.  CompanyDescriptionMaximum
Exposure
(in millions)Expiration
Date(s)On behalf of external parties:SESIGeneral indemnifications in connection with the sale of SESI including completeness and accuracy of information provided, compliance with laws, and various claimsNot Specified(1)NoneSpecific indemnifications in connection with the sale of SESI for estimated costs to complete or modify specific projects (2)Not Specified(1)Through project completionIndemnifications to lenders for payment of shortfalls in the event of early termination of government contracts (3)$1.22017-2018Surety bonds covering certain projects$10.5(4)Through project
completionHess Corporation (Retail Marketing Business)General indemnifications in connection with the sale including compliance with laws, completeness and accuracy of information provided and various claimsNot Specified(1)NoneEnergy Capital Partners (Competitive Generation Business)General indemnifications in connection with the sale of Northeast Generation Company (NGC) and the generating assets of Mt. Tom including compliance with tax and environmental laws, and various claimsNot Specified(1)November 2009On behalf of subsidiaries:CL&PSurety bonds (5)$2.62009-2010PSNHSurety bonds (5)$3.82009-2010Letters of credit$101.02009-2010WMECOSurety bonds (5)$3.0June 2009HWPSurety bonds (5)$1.0May 2009NAESCO (North Atlantic Energy Service Corporation)Surety bonds (5)$1.6May 2009Rocky River Realty CompanyLease payments for real estate$9.62024NUSCO (Northeast Utilities Service Company)Lease payments for fleet of vehicles$7.3NoneSurety bonds (5)$1.0May 2009Lease payments for real estate$2.02019E.S. Boulos Company (Boulos)Surety bonds covering ongoing projects$31.6Through project
completionNGSPerformance guarantee and insurance bonds$20.4(6)2020 (6)Select EnergyPerformance guarantees for wholesale contracts$19.3(7)2013Letters of credit$2.0January 2010Other - CYAPCSurety bonds (5)$0.3April 2010  (1) There is no specified maximum exposure included in the related sale agreements.   20





(2) The fair value for amounts recorded for these indemnifications was $0.2 million at March 31, 2009.  (3) The fair value for amounts recorded for these indemnifications was $0.1 million at March 31, 2009.  (4) The project comprising $10 million of the maximum exposure for these guarantees has been conditionally accepted by the customer and the completion of remaining work is underway.  (5) Surety bond expiration dates reflect bond termination dates (which may be renewed or extended) for specified term bonds and/or bill-to dates for bonds with no fixed term.  (6) Included in the maximum exposure is $19.2 million related to a performance guarantee of Northeast Generation Services Company (NGS) obligations for which there is no specified maximum exposure in the agreement.  The maximum exposure is calculated as of March 31, 2009 based on limits of NGS's liability contained in the underlying service contract and assumes that NGS will perform under that contract through its expiration in 2020.  The remaining $1.2 million of maximum exposure relates to insurance bonds with no expiration date that are billed annually on their anniversary date.  (7) Maximum exposure is as of March 31, 2009; however, exposures vary with underlying commodity prices and for certain contracts are essentially unlimited.  CL&P, PSNH and WMECO have no guarantees of the performance of third parties.  Many of the underlying contracts that NU guarantees, as well as certain surety bonds, contain credit ratings triggers that would require NU to post collateral in the event that NU's credit ratings are downgraded below investment grade.  6. COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO, NU Enterprises, Yankee Gas) Total comprehensive income, which includes all comprehensive income/(loss) items, net of tax and by category, for the three months ended March 31, 2009 and 2008 is as follows:  Three Months Ended March 31, 2009(Millions of Dollars)NUCL&PPSNHWMECONU
EnterprisesYankee
GasOtherNet income/(loss)$99.1$53.1$17.5$6.1$5.8$19.3$(2.7)Comprehensive income/(loss) items:Qualified cash flow hedging instruments-0.1----(0.1)Decrease in unrealized gains on securities-------Pension, SERP and PBOP benefits0.2---0.1-0.1Net change in comprehensive
    income/(loss) items0.20.1--0.1--Total comprehensive income/(loss)99.353.217.56.15.919.3(2.7)Comprehensive income/(loss) attributable 
  to noncontrolling interests1.4------Comprehensive income/(loss) attributable 
  to controlling interests$97.9$53.2$17.5$6.1$5.9$19.3$(2.7)  Three Months Ended March 31, 2008(Millions of Dollars)NUCL&PPSNHWMECONU
EnterprisesYankee
GasOtherNet income/(loss)$59.8$46.1$16.7$6.3$1.9$18.6$(29.8)Comprehensive (loss)/income items:Qualified cash flow hedging items(18.7)(8.5)(3.2)--(2.5)(4.5)(Decrease)/increase in unrealized gains 
    on securities(0.7)--0.1--(0.8)Pension, SERP and PBOP benefits1.2---0.3-0.9Net change in comprehensive
    (loss)/income items(18.2)(8.5)(3.2)0.10.3(2.5)(4.4)Total comprehensive income/(loss)41.637.613.56.42.216.1(34.2)Comprehensive income/(loss) attributable 
  to noncontrolling interests1.4------Comprehensive income/(loss) attributable
  to controlling interests$40.2$37.6$13.5$6.4$2.2$16.1$(34.2)  Comprehensive income amounts included in the Other column primarily relate to NU parent and NUSCO.  21





Fair value adjustments included in accumulated other comprehensive (loss)/income for qualified cash flow hedging instruments are as follows:  NU Consolidated(Millions of Dollars, Net of Tax)For the Three
Months Ended
March 31, 2009For the Twelve
Months Ended
December 31, 2008Balance at beginning of period$(4.6)$2.3Hedged transactions recognized into earnings-0.4Change in fair value of interest rate swap agreements-(7.0)Cash flow transactions entered into for period-(0.3)Net change associated with hedging transactions-(6.9)Total fair value adjustments included in 
  accumulated other comprehensive loss$(4.6)$(4.6)  Three Months Ended March 31, 2009Twelve Months Ended December 31, 2008(Millions of Dollars, Net of Tax)CL&PPSNHWMECOCL&PPSNHWMECOBalance at beginning of period$(3.6)$(0.8)$0.1$(0.3)$0.6$0.2Hedged transactions recognized into earnings0.1--0.40.2(0.1)Change in fair value of interest rate swap agreements---(3.7)(1.4)-Cash flow transactions entered into for period----(0.2)-Net change associated with hedging transactions0.1--(3.3)(1.4)(0.1)Total fair value adjustments included in 
  accumulated other comprehensive (loss)/income$(3.5)$(0.8)$0.1$(3.6)$(0.8)$0.1  Hedged transactions recognized into earnings in the tables above represent amounts that were reclassified from accumulated other comprehensive income into earnings in connection with the consummation of interest rate swap agreements and the amortization of existing interest rate hedges.  There were no forward starting interest rate swaps entered into for the three months ended March 31, 2009.  The following table provides the forward starting interest rate swap transactions entered into by the company, CL&P, PSNH and Yankee Gas to hedge interest rate risk associated with their respective long-term debt issuances in 2008.  2008NU ParentCL&PPSNHYankee GasLong-term debt issued (in millions)$250$300$110$100Date entered into swap transaction12/3/0712/5/0712/4/0712/4/07Term5-year10-year10-year10-yearTermination date6/2/085/19/083/24/089/23/08Charge to accumulated other comprehensive 
  income (net of tax) (1)$0.1$2.3$0.9(2)$0.7  (1) The charge to accumulated other comprehensive income will be amortized into earnings over the terms of each respective long-term debt.  (2) The amount charged to accumulated other comprehensive income is net of ineffectiveness of $0.2 million related to the settlement of a previous forward starting swap agreement later replaced at its scheduled termination date with a new swap to extend the hedging relationship to the revised pricing date of the long-term debt.  For NU consolidated, it is estimated that a charge of $0.2 million will be reclassified from accumulated other comprehensive income as a decrease to earnings over the next 12 months as a result of amortization of the interest rate swap agreements, which have been settled.  Included in this amount are estimated charges of $0.4 million and $0.1 million for CL&P and PSNH, respectively, and a benefit of $0.1 million for WMECO.  At March 31, 2009, it is estimated that a pre-tax amount of $0.7 million included in the accumulated other comprehensive income balance will be reclassified as a decrease to earnings over the next 12 months related to Pension, SERP and PBOP benefits adjustments for NU consolidated.  7. EARNINGS PER SHARE (NU) Earnings per share (EPS) is computed based upon the monthly weighted average number of common shares outstanding, excluding unallocated Employee Stock Ownership Plan (ESOP) shares, during each period.  Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock.  There were no antidilutive options outstanding for the three-month periods ended March 31, 2009 and 2008.  The monthly weighted average common shares outstanding at March 31, 2009 include the impact of the issuance of approximately 19 million common shares on March 20, 2009.  22





The following table sets forth the components of basic and fully diluted EPS:  For the Three Months Ended March 31,(Millions of Dollars, Except for Share Information)20092008Net income attributable to controlling interests$97.7$58.4Basic common shares outstanding (average)162,340,475155,286,111Dilutive effect584,692435,499Fully diluted common shares outstanding (average)162,925,167155,721,610Basic and Fully Diluted EPS$0.60$0.38  Restricted share units (RSUs) are included in basic common shares outstanding when RSUs have vested and common shares are issued.  The dilutive effect of outstanding RSUs for which common shares have not been issued is calculated using the treasury stock method.  Assumed proceeds of RSUs under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit.  The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the RSUs (the difference between the market value of RSUs using the average market price during the period and the grant date market value).  The dilutive effect of stock options is also calculated using the treasury stock method.  Assumed proceeds for stock options consist of remaining compensation cost to be recognized, cash proceeds that would be received upon exercise, and a theoretical tax benefit.  The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the average stock options outstanding for the period using the average market price and the grant price).  Allocated ESOP shares are included in basic common shares outstanding in the above table.  8. LONG-TERM DEBT (CL&P) On February 13, 2009, CL&P issued $250 million of Series A first mortgage bonds with a coupon rate of 5.5 percent and a maturity date of February 1, 2019.  The proceeds from this issuance were used to repay short-term debt and to fund CL&P's ongoing capital investment programs.  The indenture under which the bonds were issued requires CL&P to comply with certain covenants as are customarily included in such indentures.  CL&P is in compliance with these covenants at March 31, 2009.  9. SEGMENT INFORMATION (All Companies) Presentation: NU is organized between the regulated companies and NU Enterprises businesses based on a combination of factors, including the characteristics of each business' products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates.  Cash flows for total investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.  Segment information for all periods presented has been reclassified to conform to the current period presentation.  The regulated companies segments, including the electric distribution and transmission segments, as well as the gas distribution segment (Yankee Gas), represented approximately 99 percent of NU's total consolidated revenues for the three months ended March 31, 2009 as compared to 98 percent for the 2008 period.  CL&P's, PSNH's and WMECO's complete condensed consolidated financial statements are included in this combined Quarterly Report on Form 10-Q.  PSNH's distribution segment includes generation activities.  Also included in this combined Quarterly Report on Form 10-Q is detailed information regarding CL&P's, PSNH's, and WMECO's transmission segments.  The NU Enterprises segment is comprised of the following:  1) Select Energy (wholesale contracts), 2) NGS, 3) Boulos, 4) NGS Mechanical, and 5) NU Enterprises parent.  Other in the segment tables primarily consists of 1) the results of NU parent, which includes other income related to the equity in earnings of NU parent's subsidiaries and interest income from the NU Money Pool, which are both eliminated in consolidation, and interest income and expense related to the cash and debt of NU parent, respectively, 2) the revenues and expenses of NUs service companies, most of which are eliminated in consolidation, and 3) the results of other subsidiaries, which are comprised of Rocky River Realty Company and The Quinnehtuk Company (real estate subsidiaries), Mode 1 Communications, Inc., the results of the non-energy-relatedsubsidiaries of Yankee Energy System, Inc. (Yankee Energy Services Company, Yankee Energy Financial Services Company and NorConn Properties, Inc.) and the remaining operations of HWP that were not exited as part of the sale of the competitive generation business.   23





NU's segment information for the three months ended March 31, 2009 and 2008 is as follows (certain amounts presented in the financial statements may differ from amounts presented in the segment schedules due to rounding):  For the Three Months Ended March 31, 2009Regulated CompaniesDistribution (1)(Millions of Dollars)ElectricGasTransmissionNU EnterprisesOtherEliminationsTotalOperating revenues$1,246.0$201.8$134.2$20.7$107.1$(116.3)$1,593.5Depreciation and amortization(127.3)(6.7)(17.4)(0.1)(3.3)0.2(154.6)Other operating expenses(1,029.2)(157.7)(39.5)(9.8)(98.3)112.9(1,221.6)Operating income89.537.477.310.85.5(3.2)217.3Interest expense, net of AFUDC(37.9)(6.4)(17.6)(1.2)(10.1)2.2(71.0)Interest income0.9-0.1-2.5(2.3)1.2Other income/(loss), net3.8-(0.8)-81.9(81.9)3.0Income tax (expense)/benefit(15.6)(11.7)(23.0)(3.8)3.3(0.6)(51.4)Net income40.719.336.05.883.1(85.8)99.1Net income attributable to noncontrolling interests(0.8)-(0.6)---(1.4)Net income attributable to controlling interests$39.9$19.3$35.4$5.8$83.1$(85.8)$97.7Total assets$8,998.9$1,389.0$3,076.2$99.7$5,576.7$(4,866.9)$14,273.6Cash flows for total investments 
  in plant (2)$128.7$13.3$59.4$-$7.5$-$208.9  For the Three Months Ended March 31, 2008Regulated CompaniesDistribution (1)(Millions of Dollars)ElectricGasTransmissionNU EnterprisesOtherEliminationsTotalOperating revenues$1,198.1$199.6$94.8$33.8$100.0$(106.3)$1,520.0Depreciation and amortization(128.9)(6.3)(10.8)(0.1)(4.0)0.1(150.0)Other operating expenses(981.7)(158.3)(31.7)(29.2)(140.7)103.9(1,237.7)Operating income/(loss)87.535.052.34.5(44.7)(2.3)132.3Interest expense, net of AFUDC(41.6)(5.3)(10.4)(1.6)(5.9)2.2(62.6)Interest income0.9-0.40.31.7(2.2)1.1Other income, net6.8-5.6-74.0(74.0)12.4Income tax (expense)/benefit(17.5)(11.1)(14.9)(1.3)22.0(0.6)(23.4)Net income36.118.633.01.947.1(76.9)59.8Net income attributable to 
  noncontrolling interests(0.9)-(0.5)---(1.4)Net income attributable to 
  controlling interests$35.2$18.6$32.5$1.9$47.1$(76.9)$58.4Cash flows for total investments 
  in plant (2)$90.2$12.3$177.0$-$8.6$-$288.1  (1) Includes PSNH's generation activities.  (2) Cash flows for total investments in plant included in the segment information above are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.  The information related to the distribution and transmission segments for CL&P, PSNH and WMECO for the three months ended March 31, 2009 and 2008 is as follows:  CL&P - For the Three Months Ended March 31, 2009(Millions of Dollars)DistributionTransmissionTotalOperating revenues$843.8$110.7$954.5Depreciation and amortization(85.6)(14.4)(100.0)Other operating expenses(709.5)(29.6)(739.1)Operating income48.766.7115.4Interest expense, net of AFUDC(22.5)(15.2)(37.7)Interest income0.70.10.8Other income/(loss), net2.9(1.0)1.9Income tax expense(7.4)(19.9)(27.3)Net income$22.4$30.7$53.1Total assets$5,895.4$2,430.9$8,326.3Cash flows for total investments in plant (2)$77.7$38.6$116.3   24





CL&P - For the Three Months Ended March 31, 2008(Millions of Dollars)DistributionTransmissionTotalOperating revenues$812.1$73.4$885.5Depreciation and amortization(88.0)(8.5)(96.5)Other operating expenses(675.5)(23.7)(699.2)Operating income48.641.289.8Interest expense, net of AFUDC(26.3)(8.7)(35.0)Interest income0.60.41.0Other income, net6.44.811.2Income tax expense(9.5)(11.4)(20.9)Net income$19.8$26.3$46.1Cash flows for total investments in plant (2)$52.3$144.7$197.0  PSNH - For the Three Months Ended March 31, 2009(Millions of Dollars)Distribution (1)TransmissionTotalOperating revenues$291.3$16.4$307.7Depreciation and amortization(32.7)(2.1)(34.8)Other operating expenses(230.1)(6.7)(236.8)Operating income28.57.636.1Interest expense, net of AFUDC(10.9)(1.7)(12.6)Interest income0.1-0.1Other income, net1.10.31.4Income tax expense(5.3)(2.2)(7.5)Net income$13.5$4.0$17.5Total assets$2,230.4$373.3$2,603.7Cash flows for total investments in plant (2)$39.2$13.3$52.5  PSNH - For the Three Months Ended March 31, 2008(Millions of Dollars)Distribution (1)TransmissionTotalOperating revenues$276.7$15.1$291.8Depreciation and amortization(30.2)(1.6)(31.8)Other operating expenses(219.8)(5.3)(225.1)Operating income26.78.234.9Interest expense, net of AFUDC(10.9)(1.1)(12.0)Interest income0.10.10.2Other income, net0.40.71.1Income tax expense(4.8)(2.7)(7.5)Net income$11.5$5.2$16.7Cash flows for total investments in plant (2)$31.0$25.7$56.7  WMECO - For the Three Months Ended March 31, 2009(Millions of Dollars)DistributionTransmissionTotalOperating revenues$111.0$7.1$118.1Depreciation and amortization(9.1)(0.8)(9.9)Other operating expenses(89.7)(3.2)(92.9)Operating income12.23.115.3Interest expense, net of AFUDC(4.4)(0.8)(5.2)Interest income0.1-0.1Other loss, net(0.2)(0.1)(0.3)Income tax expense(2.9)(0.9)(3.8)Net income$4.8$1.3$6.1Total assets$880.4$172.5$1,052.9Cash flows for total investment in plant (2)$11.8$7.4$19.2   25





WMECO - For the Three Months Ended March 31, 2008(Millions of Dollars)DistributionTransmissionTotalOperating revenues$109.4$6.4$115.8Depreciation and amortization(10.7)(0.7)(11.4)Other operating expenses(86.4)(2.8)(89.2)Operating income12.32.915.2Interest expense, net of AFUDC(4.4)(0.7)(5.1)Interest income0.1-0.1Other income, net-0.10.1Income tax expense(3.2)(0.8)(4.0)Net income$4.8$1.5$6.3Cash flows for total investments in plant (2)$6.9$6.6$13.5  (1) Includes PSNH's generation activities.  (2) Cash flows for total investments in plant included in the segment information above are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.  10. COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (NU) A summary of the changes in common shareholders' equity and noncontrolling interest of NU for the three months ended March 31, 2009 and 2008 is as follows:  For the Three Months Ended March 31,20092008(Millions of Dollars)Common
Shareholders'
EquityNoncontrolling
InterestCommon
Shareholders'
EquityNoncontrolling
InterestBalance, beginning of period$3,020.3$116.2$2,913.8$116.2Net income99.1-59.8-Dividends on common shares(37.3)-(31.2)-Dividends on preferred shares of CL&P(1.4)(1.4)(1.4)(1.4)Issuance of common shares387.4-4.0-Capital stock expenses, net(12.6)---Other transactions, net0.4---Net income attributable to noncontrolling interests-1.4-1.4Other comprehensive income/(loss) (Note 6)0.2-(18.2)-Balance, end of period$3,456.1$116.2$2,926.8$116.2  11. SUBSEQUENT EVENTS (Yankee Gas, CL&P) On April 1, 2009, Yankee Gas retired, through borrowings from the NU Money Pool, $50 million of first mortgage bonds carrying a coupon of 6.2 percent that were issued in January 1999.  On April 2, 2009, CL&P completed the remarketing and reissuance of $62 million of pollution control revenue bonds (PCRBs) it had elected to acquire in October 2008.  The PCRBs, which mature on May 1, 2031, carry a coupon of 5.25 percent during the current fixed-rate period and are subject to a mandatory tender for purchase on April 1, 2010.    26





REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM   To the Board of Trustees and Shareholders of Northeast Utilities:   We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries (the "Company") as of March 31, 2009, and the related condensed consolidated statements of income and cash flows for the three-month periods ended March 31, 2009 and 2008.  These interim financial statements are the responsibility of the Companys management.  We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.  It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.  Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.  We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and consolidated statement of capitalization of Northeast Utilities and subsidiaries as of December 31, 2008, and the related consolidated statements of income, comprehensive income, shareholders equity, and cash flows for the year then ended prior to retrospective adjustment for the adoption of Financial Accounting Standards Board ("FASB") Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements an amendment of ARB No. 51, (not presented herein); and in our report dated February 27, 2009 (which report included an explanatory paragraph related to the adoption of FASB Statement No. 157, Fair Value Measurements, as of January 1, 2008), we expressed an unqualified opinion on those consolidated financial statements.  We also audited the adjustments described in Note 1 that were applied to retrospectively adjust the December 31, 2008 consolidated balance sheet of Northeast Utilities and subsidiaries (not presented herein). In our opinion, such adjustments are appropriate and have been properly applied to the previously issued consolidated balance sheet in deriving the accompanying retrospectively adjusted condensed consolidated balance sheet as of December 31, 2008.   /s/
Deloitte & Touche LLPDeloitte & Touche LLP   Hartford, Connecticut May 8, 2009   27





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THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES   29





THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIESCONDENSED CONSOLIDATED BALANCE SHEETS(Unaudited)March 31,December 31,(Thousands of Dollars)20092008ASSETSCurrent Assets:Cash$                8,207$                       -Receivables, less provision for uncollectibleaccounts of $27,892 in 2009 and $23,956 in 2008404,029416,304Accounts receivable from affiliated companies3,58511,215Notes receivable from affiliated companies28,488-Unbilled revenues111,251127,844Materials and supplies54,34270,676Derivative assets - current4,14030,478Prepayments and other25,35515,685639,397672,202Property, Plant and Equipment:Electric utility6,301,9686,244,705Less: Accumulated depreciation1,373,2561,346,0624,928,7124,898,643Construction work in progress217,061190,4815,145,7735,089,124Deferred Debits and Other Assets:Regulatory assets2,225,7182,274,088Derivative assets - long-term211,246215,288Other104,17485,4162,541,1382,574,792Total Assets$         8,326,308$      8,336,118The accompanying notes are an integral part of these condensed consolidated financial statements.   30





THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIESCONDENSED CONSOLIDATED BALANCE SHEETS(Unaudited)March 31,December 31,(Thousands of Dollars)20092008LIABILITIES AND CAPITALIZATIONCurrent Liabilities:Notes payable to banks$        113,972$        187,973Notes payable to affiliated companies-102,725Accounts payable277,671353,584Accounts payable to affiliated companies53,75757,053Accrued taxes54,65324,839Accrued interest33,78737,567Derivative liabilities - current13,4768,873Other71,59492,444618,910865,058Rate Reduction Bonds330,702378,195Deferred Credits and Other Liabilities:Accumulated deferred income taxes841,882811,405Accumulated deferred investment tax credits18,19318,805Deferred contractual obligations127,708132,687Regulatory liabilities322,062363,547Derivative liabilities - long-term835,258848,106Accrued pension84,64089,254Accrued postretirement benefits96,48198,587Other223,913215,6202,550,1372,578,011Capitalization:Long-Term Debt2,519,7332,270,414Preferred Stock Not Subject to Mandatory Redemption116,200116,200Common Stockholder's Equity:Common stock, $10 par value - authorized24,500,000 shares; 6,035,205 shares outstandingin 2009 and 200860,35260,352Capital surplus, paid in1,493,1911,454,198Retained earnings640,559617,276Accumulated other comprehensive loss(3,476)(3,586)Common Stockholder's Equity2,190,6262,128,240Total Capitalization4,826,5594,514,854Commitments and Contingencies (Note 5)Total Liabilities and Capitalization$     8,326,308$     8,336,118The accompanying notes are an integral part of these condensed consolidated financial statements.   31





THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIESCONDENSED CONSOLIDATED STATEMENTS OF INCOME(Unaudited)Three Months Ended March 31,(Thousands of Dollars)20092008Operating Revenues$          954,503$          885,499Operating Expenses:Operation -Fuel, purchased and net interchange power514,386493,808Other139,411129,043Maintenance27,11529,280Depreciation46,43338,869Amortization of regulatory assets, net13,00719,584Amortization of rate reduction bonds40,55738,031Taxes other than income taxes58,18947,070Total operating expenses839,098795,685Operating Income115,40589,814Interest Expense:Interest on long-term debt31,68623,607Interest on rate reduction bonds5,7998,216Other interest2093,157Interest expense, net37,69434,980Other Income, Net2,70812,123Income Before Income Tax Expense80,41966,957Income Tax Expense27,28420,889Net Income$            53,135$            46,068The accompanying notes are an integral part of these condensed consolidated financial statements.   32





THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIESCONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS(Unaudited)Three Months Ended March 31,(Thousands of Dollars)20092008Operating Activities:Net income$              53,135$             46,068Adjustments to reconcile to net cash flowsprovided by operating activities:Depreciation46,43338,869Deferred income taxes19,24033,694Bad debt expense2,6441,889Pension income and PBOP expense, net of capitalized portion, and contributions(2,437)(5,131)Regulatory refunds and underrecoveries(25,050)(85,861)Amortization of regulatory assets, net13,00719,584Amortization of rate reduction bonds40,55738,031Deferred contractual obligations(5,730)(5,702)Other(3,062)1,066Changes in current assets and liabilities:Receivables and unbilled revenues, net29,919(14,813)Investments in securitizable assets-33,316Materials and supplies(974)(4,703)Other current assets(9,736)(7,529)Accounts payable(55,938)(17,742)Taxes receivable/accrued33,19926,184Other current liabilities(13,638)(4,930)Net cash flows provided by operating activities121,56992,290Investing Activities:Investments in property and plant(116,325)(196,997)Increase in NU Money Pool lending(28,488)-Rate reduction bond escrow and other deposits(2,185)7,474Other investing activities1,491606Net cash flows used in investing activities(145,507)(188,917)Financing Activities:Cash dividends on common stock(28,462)(26,615)Cash dividends on preferred stock(1,390)(1,390)(Decrease)/increase in short-term debt(74,001)150,000Decrease in NU Money Pool borrowings(102,725)(31,800)Capital contributions from NU parent39,00057,058Issuance of long-term debt250,000-Retirements of rate reduction bonds(47,493)(44,536)Other financing activities(2,784)(183)Net cash flows provided by financing activities32,145102,534Net increase in cash8,2075,907Cash - beginning of period-538Cash - end of period$                8,207$               6,445The accompanying notes are an integral part of these condensed consolidated financial statements.   33





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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE   35





PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIESCONDENSED CONSOLIDATED BALANCE SHEETS(Unaudited)March 31,December 31,(Thousands of Dollars)20092008ASSETSCurrent Assets:Cash$                   956$                   195Receivables, less provision for uncollectibleaccounts of $4,504 in 2009 and $4,165 in 2008109,390108,857Notes receivable from affiliated companies5,60053,800Accounts receivable from affiliated companies4,707264Unbilled revenues47,95641,449Taxes receivable-8,809Fuel, materials and supplies112,347113,121Derivative assets - current218843Accumulated deferred income taxes - current31,40227,345Prepayments and other7,09815,380319,674370,063Property, Plant and Equipment:Electric utility2,276,9282,238,515Less: Accumulated depreciation777,271771,2821,499,6571,467,233Construction work in progress115,710113,7521,615,3671,580,985Deferred Debits and Other Assets:Regulatory assets548,456549,934Derivative assets - long-term1,5913,826Other118,644124,025668,691677,785Total Assets$         2,603,732$         2,628,833The accompanying notes are an integral part of these condensed consolidated financial statements.   36





PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIESCONDENSED CONSOLIDATED BALANCE SHEETS(Unaudited)March 31,December 31,(Thousands of Dollars)20092008LIABILITIES AND CAPITALIZATIONCurrent Liabilities:Notes payable to banks$              45,227$              45,227Accounts payable98,466160,692Accounts payable to affiliated companies21,39331,140Accrued taxes10,470-Accrued interest16,84911,778Derivative liabilities - current86,66477,369Other21,37423,422300,443349,628Rate Reduction Bonds223,861235,139Deferred Credits and Other Liabilities:Accumulated deferred income taxes252,749253,670Accumulated deferred investment tax credits319355Deferred contractual obligations22,73823,820Regulatory liabilities114,172111,403Derivative liabilities - long-term20,39314,846Accrued pension240,850236,332Accrued postretirement benefits40,98241,849Other44,42441,297736,627723,572Capitalization:Long-Term Debt686,792686,779Common Stockholder's Equity:Common stock, $1 par value - authorized100,000,000 shares; 301 shares outstandingin 2009 and 2008--Capital surplus, paid in366,236351,245Retained earnings290,503283,219Accumulated other comprehensive loss(730)(749)Common Stockholder's Equity656,009633,715Total Capitalization1,342,8011,320,494Commitments and Contingencies (Note 5)Total Liabilities and Capitalization$         2,603,732$         2,628,833The accompanying notes are an integral part of these condensed consolidated financial statements.   37





PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIESCONDENSED CONSOLIDATED STATEMENTS OF INCOME(Unaudited)Three Months Ended March 31,(Thousands of Dollars)20092008Operating Revenues$            307,653$            291,765Operating Expenses:Operation -Fuel, purchased and net interchange power146,225141,901Other62,72853,246Maintenance15,52219,890Depreciation15,17113,502Amortization of regulatory assets, net7,9476,408Amortization of rate reduction bonds11,68611,877Taxes other than income taxes12,24410,076Total operating expenses271,523256,900Operating Income36,13034,865Interest Expense:Interest on long-term debt8,1047,278Interest on rate reduction bonds3,6584,151Other interest792558Interest expense, net12,55411,987Other Income, Net1,4251,326Income Before Income Tax Expense25,00124,204Income Tax Expense7,5067,515Net Income$              17,495$              16,689The accompanying notes are an integral part of these condensed consolidated financial statements.   38





PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIESCONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS(Unaudited)Three Months Ended March 31,(Thousands of Dollars)20092008Operating activities:Net income$              17,495$              16,689Adjustments to reconcile to net cash flowsprovided by operating activities:Depreciation15,17113,502Deferred income taxes(7,981)(7,731)Bad debt expense1,6281,159Pension and PBOP expense, net of capitalized portion, and contributions4,1432,386Regulatory overrecoveries3,4132,796Amortization of regulatory assets, net7,9476,408Amortization of rate reduction bonds11,68611,877Deferred contractual obligations(1,394)(1,383)Net settlement of cash flow hedge instruments-(4,321)Other886(3,995)Changes in current assets and liabilities:Receivables and unbilled revenues, net(13,111)(2,421)Fuel, materials and supplies4,9216,321Other current assets8,1708,569Accounts payable(66,171)1,969Taxes receivable/accrued19,279(2,565)Other current liabilities5,990(976)Net cash flows provided by operating activities12,07248,284Investing Activities:Investments in property and plant(52,531)(56,680)Decrease in NU Money Pool lending48,200-Proceeds from sales of marketable securities1,0251,073Purchases of marketable securities(1,075)(1,101)Other investing activities(328)1,748Net cash flows used in investing activities(4,709)(54,960)Financing Activities:Cash dividends on common stock(10,211)(9,094)Increase in short-term debt-20,000Increase in NU Money Pool borrowings-3,600Capital contributions from NU parent15,0005,700Retirements of rate reduction bonds(11,278)(13,131)Other financing activities(113)(65)Net cash flows (used in)/provided by financing activities(6,602)7,010Net increase in cash761334Cash - beginning of period195450Cash - end of period$                   956$                   784The accompanying notes are an integral part of these condensed consolidated financial statements.   39





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WESTERN MASSACHUSETTS ELECTRIC COMPANY  41





WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARYCONDENSED CONSOLIDATED BALANCE SHEETS(Unaudited)March 31,December 31,(Thousands of Dollars)20092008ASSETSCurrent Assets:Cash$                1,644$                       -Receivables, less provision for uncollectibleaccounts of $8,187 in 2009 and $6,571 in 200857,30456,802Accounts receivable from affiliated companies238575Unbilled revenues16,54216,694Taxes receivable1,4835,499Materials and supplies3,8843,825Marketable securities - current46,65446,428Prepayments and other2,7392,380130,488132,203Property, Plant and Equipment:Electric utility791,204781,486Less: Accumulated depreciation218,197214,694573,007566,792Construction work in progress65,39657,413638,403624,205Deferred Debits and Other Assets:Regulatory assets259,506268,417Marketable securities - long-term9,3429,322Other15,19814,342284,046292,081Total Assets$         1,052,937$         1,048,489The accompanying notes are an integral part of these condensed consolidated financial statements.   42





WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARYCONDENSED CONSOLIDATED BALANCE SHEETS(Unaudited)March 31,December 31,(Thousands of Dollars)20092008LIABILITIES AND CAPITALIZATIONCurrent Liabilities:Notes payable to banks$              75,077$              29,850Notes payable to affiliated companies26,80031,600Accounts payable34,47550,161Accounts payable to affiliated companies8,96615,047Accrued interest2,3515,824Other8,62610,715156,295143,197Rate Reduction Bonds69,49773,176Deferred Credits and Other Liabilities:Accumulated deferred income taxes188,558187,283Accumulated deferred investment tax credits1,6891,753Deferred contractual obligations35,15436,509Regulatory liabilities26,62129,826Accrued pension2,1703,577Accrued postretirement benefits17,70918,078Other13,17913,072285,080290,098Capitalization:Long-Term Debt305,366303,868Common Stockholder's Equity:Common stock, $25 par value - authorized1,072,471 shares; 434,653 shares outstandingin 2009 and 200810,86610,866Capital surplus, paid in144,541144,545Retained earnings81,14582,549Accumulated other comprehensive income147190Common Stockholder's Equity236,699238,150Total Capitalization542,065542,018Commitments and Contingencies (Note 5)Total Liabilities and Capitalization$         1,052,937$         1,048,489The accompanying notes are an integral part of these condensed consolidated financial statements.   43





WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARYCONDENSED CONSOLIDATED STATEMENTS OF INCOME(Unaudited)Three Months Ended March 31,(Thousands of Dollars)20092008Operating Revenues$            118,081$            115,759Operating Expenses:Operation -Fuel, purchased and net interchange power63,23562,139Other22,66419,108Maintenance3,1064,577Depreciation5,5285,193Amortization of regulatory assets, net6702,755Amortization of rate reduction bonds3,6543,442Taxes other than income taxes3,8973,366Total operating expenses102,754100,580Operating Income15,32715,179Interest Expense:Interest on long-term debt3,4433,423Interest on rate reduction bonds1,1681,348Other interest627351Interest expense, net5,2385,122Other (Loss)/Income, Net(154)247Income Before Income Tax Expense9,93510,304Income Tax Expense3,7893,984Net Income$                6,146$                6,320The accompanying notes are an integral part of these condensed consolidated financial statements.   44





WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARYCONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS(Unaudited)Three Months Ended March 31,(Thousands of Dollars)20092008Operating Activities:Net income$              6,146$               6,320Adjustments to reconcile to net cash flows(used in)/provided by operating activities:Depreciation5,5285,193Deferred income taxes2,0334,228Bad debt expense2,2171,781Pension income and PBOP expense, net of capitalized portion, and contributions(621)(1,216)Regulatory underrecoveries(1,099)(2,621)Amortization of regulatory assets, net6702,755Amortization of rate reduction bonds3,6543,442Deferred contractual obligations(1,543)(1,535)Other(1,353)46Changes in current assets and liabilities:Receivables and unbilled revenues, net(1,981)(2,848)Materials and supplies(59)(643)Other current assets213241Accounts payable(20,148)(704)Taxes receivable/accrued4,016(5,324)Other current liabilities(5,561)(3,821)Net cash flows (used in)/provided by operating activities(7,888)5,294Investing Activities:Investments in property and plant(19,230)(13,498)Proceeds from sales of marketable securities35,72249,497Purchases of marketable securities(36,517)(50,076)Other investing activities369197Net cash flows used in investing activities(19,656)(13,880)Financing Activities:Cash dividends on common stock(7,550)(3,368)Increase in short-term debt45,22710,000Retirements of rate reduction bonds(3,679)(3,469)(Decrease)/increase in NU Money Pool borrowings(4,800)7,100Other financing activities(10)-Net cash flows provided by financing activities29,18810,263Net increase in cash1,6441,677Cash - beginning of period-1,110Cash - end of period$              1,644$               2,787The accompanying notes are an integral part of these condensed consolidated financial statements.   45





NORTHEAST UTILITIES AND SUBSIDIARIES Management's Discussion and Analysis of
Financial Condition and Results of Operations  The following discussion and analysis should be read in conjunction with our condensed consolidated financial statements and related combined notes included in this Quarterly Report on Form 10-Q and the Northeast Utilities and subsidiaries combined 2008 Annual Report on Form 10-K as filed with the Securities and Exchange Commission (SEC) (2008 Form 10-K).  References in this Form 10-Q to "NU," "we," "us" and "our" refer to Northeast Utilities and its consolidated subsidiaries.  All per share amounts are reported on a fully diluted basis.  The only common equity securities that are publicly traded are common shares of NU.  The earnings and earnings per share (EPS) of each segment discussed below do not represent a direct legal interest in the assets and liabilities allocated to such segment but rather represent a direct interest in our assets and liabilities as a whole.  EPS by segment is a measure not recognized under accounting principles generally accepted in the United States of America (GAAP) that is calculated by dividing the net income or loss attributable to noncontrolling interests of each segment by the average fully diluted NU common shares outstanding for the period.  We use this measure to provide segmented earnings results and guidance and believe that this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our business segments.  This non-GAAP measure should not be considered as an alternative to our consolidated fully diluted EPS determined in accordance with GAAP as an indicator of operating performance.  The discussion below also includes non-GAAP measures referencing our 2008 earnings and EPS excluding a significant charge resulting from the settlement of litigation.  We use these non-GAAP measures to more fully explain and compare the 2009 and 2008 results without including the impact of this settlement.  Due to the nature and significance of the settlement charge, management believes that this non-GAAP presentation is more representative of our performance and provides additional and useful information to investors in analyzing historical and future performance.  These measures should not be considered as alternatives to reported net income attributable to controlling interests or EPS determined in accordance with GAAP as indicators of operating performance.  Reconciliations of the above non-GAAP measures to the most directly comparable GAAP measures of consolidated fully diluted EPS and net income attributable to controlling interests are included under "Financial Condition and Business Analysis-Overview-Consolidated" and "Financial Condition and Business Analysis-Future Outlook" in this Managements Discussion and Analysis.  Financial Condition and Business Analysis  Current Economic Conditions:  The weak economic conditions in the Northeast could have a continued negative effect on our customers, which could result in greater risk of default or nonpayment.  The weak economic conditions may also limit our ability to obtain distribution rate relief or to receive approvals on major transmission projects, the cost of which will ultimately increase customer rates.  We have included our best estimate of the impacts of these factors in the assumptions that were used to develop our earnings guidance; however, we are unable to predict the ultimate impact of these conditions on our future results of operations.  Despite the weak economic conditions and remaining uncertainty with respect to the capital and credit markets, we expect to make significant investments in our capital projects in 2009 through 2013.  We believe that even under present circumstances, our current credit ratings and business profile will allow us to have adequate access to the capital markets as needed.  This belief is supported by our recent success accessing the capital markets in three separate transactions: NU parent's common share issuance resulting in $370.8 million of net proceeds in March 2009, The Connecticut Light and Power Companys (CL&P) issuance of $250 million of 10-year bonds in February 2009 at 5.5 percent, and the remarketing of $62 million of CL&Ps tax-exempt pollution control revenue bonds (PCRBs) in April 2009 at 5.25 percent.  At this point in time, while the impacts of the uncertainty in the capital and credit markets and the ongoing economic downturn cannot be predicted, we believe that we currently have sufficient operating flexibility and access to funding sources to maintain adequate liquidity.   46





Executive Summary  The following items in this executive summary are explained in more detail in this Quarterly Report:  Results, Strategy and Outlook:  · We earned $97.7 million, or $0.60 per share, in the first quarter of 2009, compared with $58.4 million, or $0.38 per share, in the first quarter of 2008.  Excluding an after-tax charge of $29.8 million, or $0.19 per share, associated with the settlement of litigation, our first quarter 2008 earnings were $88.2 million, or $0.57 per share.  · Our regulated companies, which consist of CL&P, Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), and Yankee Gas Services Company (Yankee Gas), earned $94.6 million, or $0.58 per share, in the first quarter of 2009, compared with $86.3 million, or $0.56 per share, in the first quarter of 2008.  The first quarter 2009 results included earnings of $59.2 million in the distribution segment (which includes the generation business of PSNH and gas distribution segment of Yankee Gas), and $35.4 million in the transmission segment.  In the first quarter of 2008, our distribution segment earned $53.8 million, and our transmission segment earned $32.5 million.  · Our competitive businesses held by NU Enterprises, Inc. (NU Enterprises) earned $5.8 million, or $0.04 per share, in the first quarter of 2009, compared with $1.9 million, or $0.01 per share, in the first quarter of 2008.  First quarter 2008 results include a net after-tax reduction of earnings of $3 million associated with the implementation of Statement of Financial Accounting Standards (SFAS) No. 157, "Fair Value Measurements."  · NU parent and other companies recorded net expenses of $2.7 million, or $0.02 per share, in the first quarter of 2009, compared with $29.8 million, or $0.19 per share, in the first quarter of 2008.  First quarter 2008 results include the after-tax charge of $29.8 million from the settlement of litigation.  · We continue to project consolidated 2009 earnings of between $1.80 per share and $2.00 per share, but we estimate we will earn toward the lower end of that range.  We had expected to sell new common shares in mid-2009, but advanced the timing of the issuance to March 2009 and increased the number of shares offered due to favorable market conditions.  We also maintain our previously announced 2009 EPS guidance for each of our business segments.  Legal, Regulatory and Other Items:  · On April 17, 2009, PSNH filed an application with the New Hampshire Public Utilities Commission (NHPUC) to raise distribution rates on a temporary basis by approximately $36.4 million annually, effective July 1, 2009.  PSNH expects to file an application for a permanent distribution rate increase within a few months of the temporary rate filing, with a decision expected in mid-2010.  Any differences between temporary and permanent rates will be retroactive to the point that temporary rates become effective.  · On March 24, 2009, the New Hampshire House of Representatives rejected House Bill 496, which would have placed a $250 million cap on the amount of PSNHs capital investment in its Merrimack Clean Air Project that could be reflected in customer rates.  Also on April 8, 2009, the New Hampshire Senate rejected Senate Bill 152, which would have required the NHPUC to undertake a 90-day cost-benefit analysis of the Clean Air Project.  The project is expected to cost approximately $457 million and is required by law to be operable by July 2013.  · On February 12, 2009, WMECO filed an application with the Massachusetts Department of Public Utilities (DPU) to implement an integrated, large scale solar energy program in its service territory.  WMECO proposed to install up to 6 megawatts (MW) of solar generation facilities at eight sites that include a combination of educational, industrial, landfill and utility sites at an estimated cost of $42 million.  This project could be completed as early as 2010.  WMECO also proposed the installation of another 9 MW of solar capacity by the end of 2012, subject to regulatory review.  · On April 1, 2009, WMECO filed a separate application with the DPU to develop a "smart grid" pilot for 600 to 800 lower income customers in the Springfield, Massachusetts area.  In March 2009, CL&P had enrolled 3,000 customers for a separate "smart grid" pilot that will run from June 1, 2009 through August 31, 2009.  · On March 31, 2009, CL&P and WMECO submitted a grant application to the U.S. Department of Energy (DOE) requesting matching funds for them to build an initial network of electric vehicle (EV) charging stations in their service areas at a total cost to them of $0.6 million.  The proposal for this pilot program calls for installation of 575 EV charging stations at targeted home-based, workplace and public sites, as well as the required metering capability.  This pilot is expected to help the region plan for a larger charging infrastructure for the mass-market distribution of EVs in coming years.  47





Liquidity:  · We closed on the sale of 18,975,000 common shares on March 20, 2009, resulting in $370.8 million of net proceeds to the company after underwriting commissions of $12.5 million.  The proceeds will be used to fund our regulated capital investment program.  · CL&P closed on the sale of $250 million of first mortgage bonds on February 13, 2009.  The bonds carry a coupon of 5.5 percent and will mature on February 1, 2019.  · CL&P completed the remarketing of $62 million of PCRBs on April 2, 2009.  The bonds carry a coupon of 5.25 percent and are subject to a mandatory tender for purchase on April 1, 2010.  · Our cash capital expenditures totaled $208.9 million in the first quarter of 2009, compared with $288.1 million in the first quarter of 2008.  The decrease in our cash capital expenditures was primarily the result of lower transmission segment capital expenditures, particularly at CL&P due to the completion in 2008 of three major transmission projects in southwest Connecticut.  We project cash capital expenditures of approximately $920 million in 2009.  · After rate reduction bond (RRB) payments included in financing activities, we had consolidated cash flows provided by operations in the first quarter of 2009 of $77.5 million, which represented an increase of $40.9 million from the first quarter of 2008.  The improved cash flows were primarily due to the absence in the first quarter of 2009 of the litigation settlement payment of $49.5 million in March 2008.  Refer to "Liquidity-Consolidated" in this Managements Discussion and Analysis for further discussion on first quarter 2009 operating cash flows.  We continue to project consolidated operating cash flows of approximately $500 million in 2009, after RRB payments.  · Primarily as a result of NU parent's common share offering and CL&P's first mortgage bond issuance noted above, our cash and cash equivalents totaled $416.8 million at March 31, 2009, compared with $89.8 million at December 31, 2008.At March 31, 2009, we also had $247 million of borrowing availability on our revolving credit lines, excluding the commitment of Lehman Brothers Commercial Bank (LBCB) (refer to "Liquidity - Impact of Financial Market Conditions" for further discussion).  Overview  Consolidated:  We earned $97.7 million, or $0.60 per share, in the first quarter of 2009, compared with $58.4 million, or $0.38 per share, in the first quarter of 2008.  Excluding an after-tax charge of $29.8 million, or $0.19 per share, resulting from the settlement of litigation, our earnings in the first quarter of 2008 were $88.2 million, or $0.57 per share.  A summary of our earnings by segment, which also reconciles the non-GAAP measures of consolidated non-GAAP earnings and EPS, as well as EPS by segment, to the most directly comparable GAAP measures of consolidated net income attributable to controlling interests and fully diluted EPS, for the first quarters of 2009 and 2008, is as follows:  For the Three Months Ended March 31,20092008(Millions of Dollars, except per share amounts)AmountPer ShareAmountPer ShareNet income attributable to controlling interests (GAAP)$97.7$0.60$58.4$0.38Regulated companies$94.6$0.58$86.3$0.56Competitive businesses5.80.041.90.01NU parent and other companies(2.7)(0.02)--Non-GAAP earnings97.70.6088.20.57Litigation charge (after-tax)--(29.8)(0.19)Net income attributable to controlling interests (GAAP)$97.7$0.60$58.4$0.38  Regulated Companies:Our regulated companies segment their earnings between their electric transmission segments and their electric and gas distribution segments, with PSNH generation included in the electric distribution segments.  A summary of regulated company earnings by segment for the first quarters of 2009 and 2008 is as follows:  48





For the Three Months Ended March 31,(Millions of Dollars)20092008CL&P Transmission$30.1$25.8PSNH Transmission4.05.2WMECO Transmission1.31.5Total Transmission35.432.5CL&P Distribution21.618.9PSNH Distribution13.511.5WMECO Distribution4.84.8Yankee Gas19.318.6Total Distribution59.253.8Net Income - Regulated Companies$94.6$86.3  The higher first quarter 2009 transmission segment earnings reflect a higher level of investment in this segment as we continued to build out our transmission infrastructure to meet our customers' and the regions reliability needs.  The first quarter 2009 transmission segment results primarily reflect the effect of CL&P's investment of approximately $1.6 billion since the beginning of 2005 in the southwest Connecticut transmission projects that were ultimately completed in late 2008.  The first quarter 2008 transmission segment results included earnings of approximately $3.5 million associated with an order on rehearing issued by the Federal Energy Regulatory Commission (FERC) concerning the return on equity (ROE) allowed to owners of New England electric transmission facilities, including CL&P, PSNH and WMECO.  Approximately $2.9 million of the $3.5 million related to the February 1, 2005 through December 31, 2007 time period.  CL&Ps first quarter 2009 distribution segment earnings were $2.7 million higher than the same period in 2008 primarily due to higher revenues resulting from distribution rate increases effective February 1, 2008 and February 1, 2009 and lower interest expense as a result of lower state income taxes stemming from the closure of an audit, partially offset by higher operating costs including employee benefit costs and depreciation expense.  For the 12 months ended March 31, 2009, CL&Ps distribution segment Regulatory ROE was 7.1 percent and for 2009, we expect it to be approximately 7 percent.  PSNHs first quarter 2009 distribution segment earnings were $2 million higher than the same period in 2008 primarily due to higher generation-related earnings and higher distribution revenues, partially offset by higher operating costs including employee benefit costs, depreciation expense, and property taxes.  For the 12 months ended March 31, 2009, PSNHs distribution segment Regulatory ROE was 8.4 percent and for 2009, we expect it to be approximately 8 percent.  WMECOs first quarter 2009 distribution segment earnings were unchanged from the same period in 2008.  Revenues were slightly higher in the first quarter of 2009 but were offset by higher carrying costs owed to customers on regulatory deferrals.  For the 12 months ended March 31, 2009, WMECOs distribution segment Regulatory ROE was 6.9 percent and for 2009, we expect it to be approximately 8 percent.  Yankee Gass first quarter 2009 earnings were $0.7 million higher than the same period in 2008 due to a 12.8 percent increase in firm natural gas sales partially offset by higher operating costs including repairs and maintenance, employee benefit costs, interest expense, and depreciation expense.  For the 12 months ended March 31, 2009, Yankee Gass Regulatory ROE was 8 percent and for 2009, we expect it to be approximately 9 percent.  For the distribution segment of our regulated companies, a summary of changes in CL&P, PSNH and WMECO retail electric kilowatt-hour (KWH) sales and Yankee Gas firm natural gas sales for the first quarter of 2009 as compared to the same period in 2008 on an actual and weather normalized basis (using a 30-year average) is as follows:  ElectricFirm Natural GasCL&PPSNHWMECOTotalYankee GasPercentage
Increase/
(Decrease)Weather
Normalized
Percentage
Increase/
(Decrease)Percentage
Increase/
(Decrease)Weather
Normalized
Percentage
Increase/
(Decrease)Percentage
Increase/
(Decrease)Weather
Normalized
Percentage
(Decrease)/
IncreasePercentage
Increase/
(Decrease)Weather
Normalized
Percentage
Increase/
(Decrease)Percentage
IncreaseWeather
Normalized
Percentage
IncreaseResidential4.7 %1.7 %3.1 %1.0 %1.9 %(0.7)%4.1 %1.3 %11.2%4.3%Commercial(2.3)%(3.0)%(1.5)%(2.1)%(3.1)%(3.5)%(2.2)%(2.9)%15.0%8.5%Industrial(24.1)%(24.1)%(8.0)%(8.0)%(16.0)%(16.0)%(18.3)%(18.3)%12.1%9.9%Other5.9 %5.9 %(5.5)%(5.5)%40.5 %40.5%7.6 %7.6 %--Total(1.5)%(3.2)%(0.7)%(1.8)%(3.2)%(4.4)%(1.5)%(3.0)%12.8%7.2%   49





A summary of our retail electric sales in gigawatt hours for CL&P, PSNH and WMECO and firm natural gas sales in million cubic feet for Yankee Gas for the first quarter of 2009 and 2008 is as follows:  For the Three Months Ended March 31,ElectricFirm Natural Gas20092008Percentage
Increase/(Decrease)20092008Percentage
IncreaseResidential4,1483,9854.1 %6,4615,80911.2%Commercial3,6333,716(2.2)%6,2675,45015.0%Industrial1,0091,234(18.3)%4,3063,84212.1%Other98917.6 %---Total8,8889,026(1.5)%17,03415,10112.8%  First quarter 2009 actual and weather normalized retail electric sales for all three electric companies were lower than the same period in 2008, but residential sales were higher, which contributed to higher distribution revenues in the first quarter of 2009.  As compared to other customer classes, we recover a greater portion of residential revenues through volumetric charges.  The higher residential sales in the first quarter of 2009 translated proportionately into higher distribution revenues.  In contrast to residential rates, a much smaller portion of commercial and industrial revenues are recovered through volumetric charges.  In fact, certain large business rates are structured so that we recover 100 percent of the distribution revenues through non-volumetric charges.  In this regard, rate design has significantly mitigated the impact of the declining commercial and industrial sales on distribution revenues and earnings.  The decline in industrial sales for the first quarter of 2009 reflects the fact that many industrial customers have been severely impacted by the economic conditions of our region and the nation.  Although some industrial facilities have closed, we believe the reduction in industrial sales is primarily driven by a reduced number of shifts and days of operations.  In this regard, a portion of these reduced industrial sales may be regained when the economy begins to recover.  Further, commercial and industrial sales in the first quarter of 2009 were negatively impacted by additional installation of distributed generation, utilization of conservation and load management programs, and other measures employed by customers to reduce their usage of electricity.  Firm natural gas sales on an actual and weather normalized basis were higher in the first quarter of 2009 than the same period in 2008. First quarter 2009 commercial and industrial sectors have benefitted substantially from the addition of new large gas-fired distributed generation in Yankee Gass service territory during the last twelve months.  The rate of growth in gas sales is expected to moderate for the balance of 2009 as the weak economic conditions are expected to continue until later in 2009 or early 2010, and as the large distributed generation load additions are reflected in future year-over-year comparisons.  Yankee Gas recovers approximately 40 percent of its total distribution revenues through non-usage charges, and thus changes in sales result in less of an impact in revenues.  Our uncollectibles expense is influenced by the economic conditions of our region; however, a portion of the uncollectibles expense for each of the electric distribution companies is allocated to the respective company's energy supply rate and recovered as a tracked expense.  Additionally, for CL&P and Yankee Gas, write-offs attributable to hardship customers are tracked and fully recovered.  For the first quarter of 2009, our total uncollectibles expense was approximately $3.1 million higher than the same period in 2008, but consistent with our expectations.  Competitive Businesses:  NU Enterprises, which continues to manage to completion Select Energy Inc.'s (Select Energy) remaining wholesale marketing contracts and to manage its energy services activities, earned $5.8 million in the first quarter of 2009, compared with $1.9 million in the first quarter of 2008.  First quarter 2008 results included a net after-tax reduction of earnings of $3 million associated with the implementation of SFAS No. 157.  Competitive business earnings for the first quarter of 2009 and 2008 included positive mark-to-market after-tax results of $3.2 million and $0.5 million, respectively, associated with Select Energy's wholesale marketing contracts.  NU Parent and Other Companies:NU parent and other companies recorded net expenses of $2.7 million in the first quarter of 2009, compared with net expenses of $29.8 million in the first quarter of 2008.  The net expenses in the first quarter of 2008 resulted from the payment by NU parent of $49.5 million in March 2008 as part of a comprehensive settlement of litigation initiated in 2001 over a proposed but unconsummated merger.  Excluding the $29.8 million after-tax impact of this settlement in 2008, the increase in net expenses for 2009 was primarily due to higher interest expense from the replacement of $150 million of 3.3 percent senior notes that matured on June 1, 2008 with $250 million of 5.65 percent senior notes.  Future Outlook  EPS Guidance:  We project consolidated 2009 results will be at the lower end of the earnings range of between $1.80 per share and $2.00 per share.  This projection includes the impact of the issuance of 18,975,000 common shares on March 20, 2009, which was originally forecast for mid-2009 with a lower number of shares.   50





A summary of our projected 2009 EPS by segment, which also reconciles consolidated fully diluted EPS to the non-GAAP measures of EPS by segment, is as follows:  2009 EPS Range(Approximate amounts)LowHighFully Diluted EPS (GAAP)$1.80$2.00Regulated companies:Distribution segment$1.00$1.10Transmission segment0.850.90Total regulated companies1.852.00Competitive businesses0.000.05NU parent and other companies(0.05)(0.05)Fully Diluted EPS (GAAP)$1.80$2.00  Long-Term Growth Rate:We project that we will achieve an average compounded annual EPS growth rate of between 8 percent and 11 percent over 2007 EPS of $1.59 through 2013.  We continue to estimate we will likely be at the lower end of this range.  This EPS growth rate assumes achieved Regulatory ROEs of approximately 12 percent for transmission, between 9.5 percent and 10 percent for generation and between 9 percent and 9.5 percent for distribution investments.  We believe this growth will be achieved if our capital program is completed in accordance with our plans, distribution rate case orders enable us to earn the assumed Regulatory ROEs and FERC's present transmission policies remain consistent and enable us to achieve projected transmission ROEs.  Liquidity  Consolidated:We had $416.8 million of cash and cash equivalents on hand at March 31, 2009, compared with $89.8 million at December 31, 2008.  During the first quarter of 2009, our cash position increased primarily as a result of the proceeds of $370.8 million from the issuance of 18,975,000 common shares on March 20, 2009, net of underwriting commissions of $12.5 million, and the issuance of $250 million of first mortgage bonds by CL&P on February 13, 2009.  On April 1, 2009, Yankee Gas retired through borrowings from the NU Money Pool $50 million of first mortgage bonds carrying a coupon of 6.2 percent that were issued in January 1999.  Yankee Gas does not plan to issue additional long-term debt in 2009.  On April 2, 2009, CL&P completed the remarketing of $62 million of tax-exempt PCRBs it had elected to acquire in October 2008.  The bonds carry a coupon of 5.25 percent until the mandatory tender for purchase on April 1, 2010, and have a final maturity of May 1, 2031.  On February 20, 2009, PSNH filed an application with the NHPUC to issue $150 million of first mortgage bonds.  Subject to regulatory approval, PSNH currently expects to issue the bonds in the second half of 2009.  No other debt or equity financings are planned by NU or its subsidiaries in 2009, and we have only a modest level of sinking fund requirements and no other debt maturities until April 1, 2012.  The proceeds from the above completed or planned 2009 financings were or will be primarily used to repay short-term borrowings and fund our capital programs.  The combined borrowings and letters of credit (LOCs) outstanding on our revolving credit facilities totaled $597 million as of March 31, 2009, compared with approximately $706 million as of December 31, 2008.  We had consolidated operating cash flows in the first quarter of 2009 of $77.5 million, compared with $36.6 million in the first quarter of 2008, both after RRB payments included in financing activities.  The increase in first quarter 2009 operating cash flows was primarily due to the absence in 2009 of the litigation settlement payment of $49.5 million in March 2008.  After considering this cash flow impact, the decrease in operating cash flows in 2009 from 2008 was primarily due to an increase of $156.6 million in the negative cash flow effect of our accounts payable balances as a result of, among other things, costs at PSNH and WMECO related to the major storm in December 2008 that were paid to vendors in the first quarter of 2009 and deferred and expected to be recovered from customers in future periods.  This cash flow impact was partially offset by a decrease in the negative cash flow impact from various other working capital items, and regulatory refunds and underrecoveries of $54.4 million.  We continue to project consolidated operating cash flows of approximately $500 million in 2009, after RRB payments of $244 million.   51





A summary of the current credit ratings and outlooks by Moody's Investors Service (Moody's), Standard & Poor's (S&P) and Fitch Ratings (Fitch) for NU parent and WMECOs senior unsecured debt and CL&P and PSNH's first mortgage bonds is as follows:  Moody'sS&PFitchCurrentOutlookCurrentOutlookCurrentOutlookNU ParentBaa2StableBBB-StableBBBStableCL&PA3StableBBB+StableA-StablePSNHBaa1StableBBB+StableBBB+StableWMECOBaa2StableBBBStableBBB+Stable  If NU parents senior unsecured debt ratings were to be reduced to a sub-investment grade level by either Moody's or S&P, a number of Select Energy's supply contracts would require Select Energy to post additional collateral in the form of cash or LOCs.  If such an event were to occur, Select Energy, under its remaining contracts, would have been required to provide additional cash or LOCs in an aggregate amount of $25.4 million to various unaffiliated counterparties and additional cash or LOCs in the aggregate amount of $5.9 million to an independent system operator, in each case at March 31, 2009.  NU parent would have been able to provide that collateral.  If unsecured debt ratings for CL&P or PSNH were to be reduced by either Moody's or S&P, a number of supply contracts would require CL&P and PSNH to post additional collateral in the form of cash or LOCs with various unaffiliated counterparties.  If these ratings were to be reduced by one level, PSNH would have been required to post additional collateral of $1.8 million as of March 31, 2009.  If these ratings were to be reduced by two levels or below investment grade, the amount of additional collateral required to be posted by PSNH would have been $26.5 million at March 31, 2009.  PSNH would have been able to provide these collateral amounts.  At March 31, 2009, CL&P only had one supply contract requiring collateral posting for which collateral has been posted for the out-of-the-money position.  No additional collateral would have been required under CL&P's supply contracts if its unsecured debt ratings had been reduced.  NU parent paid common dividends of $37.2 million in the first quarter of 2009, compared with $31.3 million in the first quarter of 2008.  The increase reflects a 6.3 percent increase in NU parent's common dividend rate that took effect in the third quarter of 2008 and an 11.8 percent increase that was declared in February 2009 and paid in March 2009.  On April 14, 2009, our Board of Trustees declared a common dividend of $0.2375 per share, estimated to total $41.6 million, payable on June 30, 2009 to shareholders of record as of June 1, 2009.  This dividend rate equals the rate declared in February 2009 that reflects our new policy of targeting a dividend payout ratio of approximately 50 percent of earnings.  In general, the regulated companies pay approximately 60 percent of their cash earnings to NU parent in the form of common dividends.  In the first quarter of 2009, CL&P, PSNH, WMECO, and Yankee Gas paid $28.5 million, $10.2 million, $7.6 million, and $19.1 million, respectively, in common dividends to NU parent.  In the first quarter of 2009, NU parent contributed $39 million and $15 million of equity to CL&P and PSNH, respectively.  NU parent made no such contributions to WMECO and Yankee Gas in the three months ended March 31, 2009.  NU parents ability to pay common dividends is subject to approval by its Board of Trustees and to NU's future earnings and cash flow requirements and may be limited by certain state statutes, the leverage restrictions in its revolving credit agreement and the ability of its subsidiaries to pay common dividends, but is not regulated under the Federal Power Act.  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.  CL&P, PSNH, WMECO and Yankee Gas also are parties to a revolving credit agreement that imposes leverage restrictions.  Cash capital expenditures included on the accompanying condensed consolidated statements of cash flows and described in the Liquidity section of this Management's Discussion and Analysis do not include amounts incurred on capital projects but not yet paid, cost of removal, the allowance for funds used during construction (AFUDC) related to equity funds, and the capitalized portions of pension and postretirement benefits other than pension (PBOP) expense or income.  A summary of our cash capital expenditures by company for the first quarter of 2009 and 2008 is as follows:  For the Three Months Ended March 31,(Millions of Dollars)20092008CL&P$116.3$197.0PSNH52.556.7WMECO19.213.5Yankee Gas13.412.3Other7.58.6Totals$208.9$288.1   52





The decrease in our cash capital expenditures was primarily the result of lower transmission segment capital expenditures, particularly at CL&P (refer to "Business Development and Capital Expenditures" for further discussion).  Cash capital expenditures for the first quarter of 2009 were higher than amounts reported under "Business Development and Capital Expenditures" in this Management's Discussion and Analysis due to a significant amount of capital costs incurred in 2008 that were paid in the first quarter of 2009.  NU Parent:NU parent has a credit line, in a nominal aggregate amount of $500 million including the commitment of LBCB (as further discussed below), which expires on November 6, 2010.  At March 31, 2009, NU parent had $103 million of LOCs issued for the benefit of certain subsidiaries (primarily PSNH) and $234.4 million of borrowings outstanding under this facility.  The weighted-average interest rate on these short-term borrowings at March 31, 2009 was 1.04 percent, which is based on a variable rate plus an applicable margin based on NU parent's credit ratings.  NU parent had approximately $145 million of borrowing availability on this facility as of March 31, 2009, excluding LBCBs commitment.  Regulated Companies:  The regulated companies maintain a joint credit facility in a nominal aggregate amount of $400 million including the commitment of LBCB (as further discussed below), which expires on November 6, 2010.  There were $259.6 million of borrowings outstanding under this facility at March 31, 2009 ($114 million for CL&P, $45.2 million for PSNH, $75.1 million for WMECO, and $25.3 million for Yankee Gas).  The weighted-average interest rate on these short-term borrowings at March 31, 2009 was 1.04 percent, which is based on a variable rate plus an applicable margin based on the borrower's credit ratings.  The regulated companies had approximately $102 million of borrowing availability on this facility as of March 31, 2009, excluding LBCBs commitment and subject to individual companies' borrowing limits.  Our credit facilities and bond indentures provide that NU parent and certain of its subsidiaries, including CL&P, PSNH and WMECO, must comply with certain financial and non-financial covenants as are customarily included in such agreements, including a consolidated debt to capitalization ratio.  All such companies currently are and expect to remain in compliance with these covenants.  Refer to Note 2, "Short-Term Debt," and Note 11, "Long-Term Debt," to our consolidated financial statements included in the 2008 Form 10-K for further discussion of material terms and conditions of these agreements.  Impact of Financial Market Conditions:While the impact of continued market volatility and the extent and impacts of any economic downturn cannot be predicted, we believe that we currently have sufficient operating flexibility and access to funding sources to maintain adequate liquidity (as evidenced by our 2009 equity and debt issuances described above).  The credit outlooks for NU parent and our regulated companies are all stable.  Our companies have modest risk of calls for collateral due to our business model, as described further below.  Cash contributions to our pension plan are not required until the second quarter of 2010, as further described below.  We have no long-term debt maturing until April 2012 beyond the $50 million at Yankee Gas that was repaid on April 1, 2009, projected cash capital expenditures for 2009 of $920 million are significantly less than 2008, and projected operating cash flows for 2009 are higher than 2008.  We have completed all but $150 million of our planned financings for 2009 and continue to have access to our two revolving credit facilities described above in a nominal aggregate amount of $900 million.  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; Toronto Dominion (Texas) LLC; Union Bank of California, N.A.; Wachovia Bank, N.A.; and Wells Fargo Bank, N.A.  Borrowing capacity under the facility has not been reduced as a result of the 2008 merger of Wachovia and Wells Fargo.  As a result of LBCB declining to fund its current commitment of approximately $56 million, we are limited to an aggregate of $844 million of borrowing capacity under our credit facilities, which we believe provides sufficient operating flexibility to maintain adequate liquidity.  We have no other exposure to Lehman Brothers Holdings Inc., the parent of LBCB, or any of its affiliates.  PSNH has outstanding $407.3 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 been reset by formula under the applicable documents every 35 days and has ranged 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 an interest rate of 0.3 percent at March 31, 2009.  We are not obligated to purchase these PCRBs, which mature in 2021, from the remarketing agents.  Our regulated standard offer type contracts do not require us to post collateral, but in the event of an energy suppliers default under these contracts we could be required to provide standard offer type services directly to customers until a substitute supplier could be arranged.  Our suppliers are performing on these contracts, and any additional costs we would incur from a supplier default would be recoverable from customers.  In other regulated contracts that do contain collateral posting requirements, the counterparties are generally exposed to us at this time, and when we have been exposed to them, these counterparties have been posting the necessary collateral.  As of March 31, 2009, PSNH had posted $91 million in related collateral in the form of NU LOCs with counterparties, as compared to $75 million of NU LOCs at December 31, 2008.  Also, our collateral requirements for Select Energys few remaining wholesale contracts are modest as we continue to wind down this business.  We have not experienced any significant performance difficulties with suppliers on Select Energys remaining sourcing contracts.  As of March 31, 2009, Select Energy had posted $35.7  53





million in collateral, as compared to $26.3 million at December 31, 2008.  Refer to "NU Enterprises Contracts - Counterparty Credit Risk" in this Managements Discussion and Analysis for further discussion.  As of January 1, 2008 our pension plan funded ratio (the value of plan assets divided by the funding target in accordance with the requirement of the Pension Protection Act) was 111 percent.  Our pension plan has historically been well funded, and we have not been required to make a contribution to the plan since 1991.  Primarily due to the negative financial market conditions experienced in 2008, the fair value of our pension plan assets dropped by approximately $900 million to $1.56 billion as of January 1, 2009, resulting in a projected funded ratio of approximately 77 percent.  Recent Internal Revenue Service (IRS) guidance provides us with some flexibility in determining the plans benefit liabilities.  In light of this guidance, we are currently evaluating our liability measurement methodology.  Any changes could affect the amount or timing of required contributions.  Unless there is a change in current funding requirements, a very significant recovery in the financial markets, or we elect to utilize the guidance of the IRS described above, we could be required to make a pre-tax contribution to the plan estimated to be approximately $150 million to meet minimum funding requirements for the plan year beginning January 1, 2009.  This contribution would occur in the third quarter of 2010.  No cash contribution to the plan is required to be made in 2009.  Assuming that the pension plan assets earn the long-term rate of return of 8.75 percent and corporate bond rates remain constant during 2009, we could also be required to make additional pre-tax contributions currently estimated to total between $150 million and $200 million in 2010 beginning in the second quarter for the plan year beginning January 1, 2010.  Funding requirements of this magnitude, when combined with the financing requirements of our construction program, could impact the timing and amount of future equity and debt financings.  Pension contributions will impact future levels of pension expense, and the majority of our pension expense is included in rates charged to customers of our regulated companies.  Business Development and Capital Expenditures  Consolidated:Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension and PBOP expense or income (all of which are non-cash factors), totaled $183 million in the first quarter of 2009, compared with $305.6 million in the first quarter of 2008.  These amounts included $4.4 million and $4.6 million in the first quarters of 2009 and 2008, respectively, that related to our corporate service company and other affiliated companies that support the regulated companies.  Regulated Companies:Capital expenditures for the regulated companies are expected to total $921 million in 2009, which includes $70 million related to our corporate service company and other affiliated companies that support the regulated companies.  Transmission Segment:Transmission segment capital expenditures decreased by $143.5 million in the first quarter of 2009, as compared with the same period in 2008, primarily due to reduced expenditures at CL&P, which completed three major transmission projects in southwest Connecticut in the second half of 2008.  Capital expenditures for the consolidated transmission segment are expected to total $225 million in 2009 ($97 million for CL&P).  A summary of transmission segment capital expenditures by company in the first quarters of 2009 and 2008 is as follows:  For the Three Months Ended March 31,(Millions of Dollars)20092008CL&P$36.4$171.1PSNH9.922.5WMECO10.96.9HWP-0.2*Totals$57.2$200.7  * Represents capital additions of Holyoke Water Power Company (HWP) and its subsidiary, Holyoke Power and Electric Company, which were transferred to WMECO in December 2008.  In October 2008, we commenced state siting filings for our current series of major transmission projects, New England East-West Solutions (NEEWS).  That series of projects involves our construction of new overhead 345 kilovolt (KV) lines in Massachusetts 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 USA 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 continue to estimate that CL&Ps and WMECOs total capital expenditures for these projects will be $1.49 billion through 2013, although the timing of projected annual capital spending could be affected if receipt of siting approvals is delayed.  As of March 31, 2009, CL&P and WMECO had capitalized approximately $26.3 million and $30.3 million, respectively, in costs associated with NEEWS, of which $6.6 million and $7.1 million, respectively, were capitalized in the first quarter of 2009.  Transmission capital  54





spending is driven by a number of factors, including the federal reliability requirements of the North American Electrical Reliability Corporation (NERC) and peak load growth.  As those NERC requirements evolve and as projections of peak load growth are updated, the timing of some of our principal projects will continue to be evaluated by us and by ISO-NE as part of its regional system planning process.  The first of the NEEWS projects, the Greater Springfield Reliability Project (GSRP), which involves the construction of 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 to cost approximately $714 million if built according to our preferred route configuration.  CL&P filed its application to build the Connecticut portion of the GSRP with the Connecticut Siting Council (CSC) on October 20, 2008.  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 received three proposals in response to a formal request for alternatives to the GSRP.  One of the proposals is for construction of a combined cycle generating facility in lieu of the GSRP.  The CSC is considering this application, and CL&P has filed data requests to ascertain whether the proposed generation project is a suitable alternative.  The CSC has preliminarily set dates for public comments and site visits on the Connecticut portion of the project in June 2009. If the overall project is approved in 2010, as expected, we currently expect to commence construction in late 2010/early 2011 and to place the project in service in 2013.  We do not expect the need date for GSRP to change as a result of ISO-NE's regional system planning process.  Our second major NEEWS project is the Interstate Reliability Project, which is being designed and built in coordination with National Grid USA.  CL&P's share of this project includes an approximately 40-mile, 345 KV line from Lebanon, Connecticut to the Connecticut-Rhode Island border where it would connect with enhancements National Grid USA is designing.  We continue to estimate CL&P's share of this project will cost approximately $250 million.  Municipal consultations concluded in November 2008, and CL&P plans to file siting applications with Connecticut regulators by the third quarter of 2009.  If the project is approved in late 2010 as currently expected, construction would begin as early as 2011.  We currently expect the project to be placed in service in 2013.  The third part of NEEWS is the Central Connecticut Reliability Project, which involves construction of a new line from Bloomfield, Connecticut to Watertown, Connecticut.  This line would provide 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, and CL&P currently expects to file the siting application in early 2010, with construction beginning in 2011 if the project is approved as expected.  The project is currently expected to be placed in service in 2013 at an estimated cost of approximately $315 million.  Included as part of NEEWS are approximately $210 million of associated reliability related expenditures, some of which may be incurred in advance of the three major projects.  During the siting approval process, state regulators may require changes in configuration to address local concerns that could increase construction costs.  Our current design for NEEWS does not contemplate any underground lines.  Building any lines underground, particularly 345 KV lines, would increase total costs of the project beyond those reflected above.  On December 12, 2008, NU and NSTAR submitted a joint petition for a declaratory order to the FERC.  The petition requests a ruling by the FERC that would allow NU and NSTAR to enter 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 and NSTAR would sell 1,200 MW of firm electric transmission service over a new participant-funded transmission tie line connecting New England with the Hydro-Québec system in order for HQUS to sell and deliver into New England this same amount of firm electric power from Canadian low-carbon energy resources.  A FERC order is expected in the second quarter of 2009.  Distribution Segment:  Distribution segment capital expenditures increased by $21.1 million in the first quarter of 2009, as compared with the same period in 2008, primarily due to higher capital expenditures for CL&P's electric distribution segment and increased generation business expenditures at PSNH related to its Clean Air Project further described below.  Capital expenditures for the consolidated distribution segment are expected to total $626 million in 2009 ($278 million for CL&P and $156 million for the PSNH generation business).   55





A summary of distribution segment capital expenditures by company in the first quarters of 2009 and 2008 is as follows:  For the Three Months Ended March 31,(Millions of Dollars)20092008CL&P$65.4$57.3PSNH18.419.7WMECO6.96.9Totals - Electric distribution  (excluding generation)90.783.9Yankee Gas10.27.8Other0.10.1Total distribution101.091.8PSNH generation20.48.5Total distribution segment$121.4$100.3  PSNHs Clean Air Project is expected to cost approximately $457 million, which will be recovered through its generation rates under New Hampshire law.  PSNH has commenced site work for this project, which is scheduled to be completed by the end of 2012.  Through March 31, 2009, PSNH capitalized approximately $45.2 million associated with this project, of which $17.7 million was capitalized in the first quarter of 2009.  Refer to "Regulatory Developments and Rate Matters - New Hampshire - Merrimack Clean Air Project" for further discussion, including the status of the New Hampshire Supreme Court proceedings and their effect on this project.  Smart Grid and Other Strategic Initiatives:We continue to evaluate certain development projects that would benefit our customers, such as investments in wide-spread advanced metering infrastructure (AMI) systems and other projects.  In March 2009, CL&P finished the process of enrolling 3,000 customers for its time-based rate pilot program.  The pilot will test 1,500 residential and 1,500 commercial and industrial customers interest in and response to peak time-based energy rates, coupled with smart meters.  The pilot will run from June 1, 2009 through August 31, 2009, and a report on its results will be filed with the Connecticut Department of Public Utility Control (DPUC) by December 1, 2009.  The cost of the pilot is estimated to be $13 million and is authorized to be recovered through CL&P rates.  On April 1, 2009, consistent with the Massachusetts Green Communities Act of 2007, WMECO filed an application with the DPU to develop a "smart grid" pilot for 600 to 800 customers in the Greater Springfield area of western Massachusetts.  WMECOs proposed pilot focuses on two products that could address the needs of lower income customers.  WMECO has proposed a pre-pay product, which would allow customers to pay in advance for their energy, and an inverted tier block rate that would charge customers increasing amounts per KWH as their consumption rises.  The DPU has 18 months to review the proposed design of the pilot.  On February 12, 2009, also consistent with the Massachusetts Green Communities Act of 2007 that allows for electric utility ownership of up to 50 MW of solar generating facilities, WMECO filed an application with the DPU to implement an integrated, large-scale solar energy program in its service territory.  Under the Act, the DPU has six months to issue a decision on WMECOs program.  WMECOs initial proposal is to install up to 6 MW of solar generation at eight sites that include a combination of educational, industrial, landfill and utility sites at an estimated cost of $42 million, which could be operable as early as 2010.  WMECO also proposed the installation of another 9 MW of solar capacity by the end of 2012, subject to regulatory review.  On March 31, 2009, CL&P and WMECO submitted a grant application to the DOE requesting matching funds for them to build an initial network of EV charging stations in their service areas.  A decision is expected in June 2009.  If approved, project funding will consist of $0.7 million from the DOE grant, $0.6 million from CL&P and WMECO and $0.1 million of in-kind contributions from the Greater New Haven Clean Cities Coalition.  The proposal calls for installation of 575 EV charging stations at targeted home-based, workplace and public sites within CL&P and WMECOs existing retail service areas, as well as the required metering capability.  Information from our first-round network experience is expected to help the region plan for a larger charging infrastructure that is likely to coincide with the mass-market distribution of EVs in coming years.  The estimated capital expenditures discussed above do not include expenditures for these initiatives, except for the CL&P AMI pilot program.  Transmission Rate Matters and FERC Regulatory Issues  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 these parties 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 from all market participants, has served as the Regional Transmission Organization for New England since February 1, 2005.  ISO-NE works to ensure the reliability of the New England transmission system, administers the independent system operator tariff, subject to FERC approval, oversees the efficient and  56





competitive functioning of the regional wholesale power market and determines the portion of the costs of our major transmission facilities that are regionalized throughout New England.  Transmission - Wholesale Rates:Wholesale transmission revenues are based on formula rates that are approved by the FERC.  Most of our wholesale transmission revenues are collected under the ISO-NE FERC Electric Tariff No. 3, Transmission, Markets and Services Tariff (Tariff No. 3).  Tariff No. 3 includes Regional Network Service (RNS) and Schedule 21 - NU rate schedules to recover fees for transmission and other services.  The RNS rate, administered by ISO-NE and billed to all New England transmission users, is reset on June 1st of each year and recovers the revenue requirements associated with transmission facilities that benefit the New England region.  The Schedule 21 - NU 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 recovered under the RNS rate, including 100 percent of the construction work in progress (CWIP) that is included in rate base on the NEEWS projects discussed below.  The Schedule 21 - NU rate calculation recovers total transmission revenue requirements net of revenues received from other sources (i.e., RNS, rentals, etc.), thereby ensuring that we recover all regional and local revenue requirements as prescribed in Tariff No. 3.  Both the RNS and Schedule 21 - NU rates provide for annual true-ups to actual costs.  The financial impacts of differences between actual and projected costs are deferred for future recovery from or refund to customers.  At March 31, 2009, the Schedule 21 - NU rates were in a total underrecovery position of $12.8 million ($10.5 million for CL&P), of which approximately $4.6 million ($3.8 million for CL&P) will be collected from customers in June 2009.  Legislative Matters  Environmental Legislation:The Regional Greenhouse Gas Initiative (RGGI) is a cooperative effort by ten northeastern and mid-Atlantic states, including Connecticut, New Hampshire and Massachusetts, to develop a regional program for stabilizing and reducing carbon dioxide (CO2) emissions from fossil fuel-fired electric generating plants.  RGGI proposes to stabilize CO2emissions at 2009 levels and reduce them by 10 percent from these levels by 2018.  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 sell 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 sell CO2 allowances primarily through regional auctions.  Regulated power generators are able to purchase CO2 allowances issued by any of the participating states to demonstrate compliance with the RGGI program of the state governing their generating plants.  Taken together, the individual participating state programs will function as a single regional compliance market for carbon emissions.  The third regional auction of RGGI CO2 allowances took place on March 18, 2009.  At the auction, more than 31 million CO2 allowances were sold at the clearing price of $3.51 per CO2 allowance.  Other auctions are scheduled for June, September and December 2009.  PSNH anticipates that its generating units will emit between 4 million and 5 million tons of CO2 per year after taking into account the operation of PSNHs Northern Wood Power wood-burning generating plant, which under the RGGI formula, decreased PSNHs responsibility for reducing fossil-fired CO2 emissions by approximately 425,000 tons per year, or almost ten percent.  New Hampshire law provides up to 2.5 million banked CO2 allowances per year for PSNHs fossil fueled generating plants during the 2009 to 2011 compliance period.  These banked CO2 allowances will initially comprise approximately one-half of the yearly CO2 allowances required for PSNHs generating plants to comply with RGGI, and such banked allowances will decrease over time.  PSNH expects to satisfy its remaining RGGI requirements by purchasing CO2 allowances at auction or in the market and has purchased allowances in the first three auctions.  The cost of complying with RGGI requirements is recoverable from PSNH customers.  2009 Federal Legislation:On February 17, 2009, President Obama signed into law The American Recovery and Reinvestment Act of 2009.  Among other things, the Act promotes economic stimulus and energy independence by expanding tax credit, tax deduction and financing options for developers or sponsors and supply chain providers of projects that generate electricity from renewable resources.  Specific provisions include a 30 percent credit for investment in qualified property used in a qualified advance energy project, an increase in the alternative refueling property credit percentage and credit cap, federal funding support for smart grid programs and Treasury Department funding of energy grants in lieu of tax credits.  The Act gives the Treasury Department 180 days to determine how to administer these grants.  We expect to benefit from the bonus depreciation extension, which we project will have a positive cash flow impact of approximately $50 million in 2009, and could benefit from the solar energy credit and grants.  We are currently evaluating these opportunities and cannot estimate at this time any impact that the Act will have on our earnings.  It is possible that the United States Environmental Protection Agency will promulgate regulations and/or Congress will enact legislation addressing climate change and carbon constraints.  Any such regulations or laws will likely impact PSNH's generating plants and possibly the costs that CL&P and WMECO pay for generation service from the market.  Until we review any new regulations or legislation, we cannot determine the actual impacts on any of our companies.  We would anticipate recovering related costs from customers.   57





New Hampshire:  2009 Legislation:Two bills were raised in the 2009 session of the New Hampshire state legislature that would have affected PSNHs ongoing project to install wet scrubber technology to reduce mercury and sulfur emissions at PSNHs coal-fired Merrimack generating station.  Under a 2006 New Hampshire statute, the scrubber must be operable by July 1, 2013.  On March 24, 2009, the New Hampshire House of Representatives rejected House Bill 496, which would have placed a $250 million cap on the amount of capital investment in the scrubber that PSNH could recover from customers.  On April 8, 2009, the New Hampshire Senate rejected Senate Bill 152, which would have required the NHPUC to conduct a 90-day cost-benefit review of the scrubber installation.  Regulatory Developments and Rate Matters  Connecticut - CL&P:  Distribution Rates:CL&P implemented new distribution rates in 2009 to reflect the DPUCs 2008 decision allowing a $20.1 million annualized increase in distribution rates, effective February 1, 2009.  CL&P continues to evaluate filing a new distribution rate case in either late 2009 or in 2010.  Renewable Energy Contracts:In May 2009, pursuant to Connecticut's "Act Concerning Energy Independence," the DPUC approved five renewable energy plant projects with total capacity of 27.3 MW.  Contracts for the purchase of energy, capacity and renewable energy certificates from these projects are expected to be signed by CL&P and filed with the DPUC by early July 2009.  Purchases under the contracts are scheduled to begin from September 2010 through July 2011 and to extend for 15 to 20 years.  As directed by the DPUC, CL&P and The United Illuminating Company (UI) have 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.  CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P's customers.  Standard Service and Last Resort Service Rates:  CL&P's residential and small commercial customers who do not choose competitive suppliers are served under Standard Service (SS) rates, and large commercial and industrial customers who do not choose competitive suppliers are served under Last Resort Service (LRS) rates.  Effective January 1, 2009, the DPUC approved an increase to CL&P's total average SS rate of approximately 2.4 percent and a decrease to CL&P's total average LRS rate of approximately 5.9 percent.  The energy supply portion of the total average SS rate increased from 11.852 cents per KWH to 12.316 cents per KWH.  The energy supply portion of the total average LRS rate decreased from 12.667 cents per KWH to 11.738 cents per KWH.  Effective April 1, 2009, the DPUC approved a decrease to CL&Ps total average LRS rate of approximately 22 percent, which was a result of the energy supply portion decreasing to 8.207 cents per KWH from the previous three-month period.  CL&P is fully and timely recovering the costs of its SS and LRS services.  2008 Management Audit:On August 18, 2008, a consulting firm hired by the DPUC began an on-site management audit of CL&P, which is required to be conducted every six years by statute and requires a diagnostic review of all functions of the company.  The audit has been completed, and a final audit report is expected in the second quarter of 2009.  We do not expect a material impact to CL&P's financial position or results of operations from results of this audit.  New Hampshire:  Delivery, Energy, and Stranded Cost Rate Filings:On April 17, 2009, PSNH filed an application with the NHPUC to increase its distribution rates by approximately $36.4 million annually on a temporary basis.  As part of this filing, PSNH is seeking recovery of $67.7 million of deferred major storm costs that PSNH incurred as a result of the December 2008 major ice storm.  PSNH has also notified the NHPUC that it will be making subsequent filings, in mid-May 2009, to reduce default energy service (ES) rates by approximately $63 million and increase stranded cost recovery charges (SCRC) by approximately $10.9 million.  ES costs have decreased, primarily as a result of lower fuel and purchased power costs.  SCRC costs have increased due to lower market values for existing purchased power contracts resulting in an increase in the level of over-market purchase power contracts recoverable as stranded costs.  PSNH requested that all of the rate changes, which in total would reduce customers bills by 1.3 percent, be effective on July 1, 2009.  PSNH expects to file an application for a permanent distribution rate increase within a few months of the temporary rate filing, with a decision expected in mid-2010.  Any differences between temporary and permanent rates will be retroactive to the point that temporary rates become effective.  Merrimack Clean Air Project:  In 2006, New Hampshire enacted a statute requiring PSNH to reduce the mercury emissions from its coal-fired stations by at least 80 percent through the installation of wet scrubber technology at its 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 its authority to find  58





whether the project is in the public interest.  On September 19, 2008, the NHPUC ruled that its authority is limited to determining at a later time the prudence of the costs of complying with the requirements of the scrubber legislation.  In October 2008, several parties filed motions with the NHPUC requesting a reconsideration of its ruling.  On November 12, 2008, the NHPUC issued an order denying the motions for rehearing.  On December 11, 2008, several parties involved in the filing of the October 2008 motion for rehearing filed an appeal with the New Hampshire Supreme Court requesting that the Court overturn the NHPUC's 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.  PSNH has begun extensive site work for this project in order to meet its legislatively mandated deadline and has capitalized approximately $45.2 million through March 31, 2009.  While PSNH does not expect the outcome of the Court appeal to adversely impact its ability to recover incurred costs from customers, should the Clean Air Project be canceled for any reason, resulting contract cancellation payments and termination costs would likely amount to a substantial portion of the approximately $240 million of contractual commitments as of March 31, 2009.The actual total would depend on the timing of a cancellation, if it were to occur, and related negotiations with vendors.  Massachusetts:  Distribution Rates:In December 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.  The overall impact on customers bills was a 0.5 percent increase for residential customers, a 2 percent decrease for small commercial and industrial customers, and a 3 percent decrease for medium and large commercial and industrial customers.  WMECO expects to file a distribution rate case in mid-2010 to be effective January 1, 2011.  The distribution rate case will include a proposal, as required by the DPU, to fully decouple distribution revenues from KWH sales.  Basic Service Rates:Effective January 1, 2009, the rates for all basic service customers decreased due to the decline in the cost of energy, as reflected in WMECO's basic service solicitations.  Basic service rates for residential customers decreased from 12.1 cents per KWH to 11.8 cents per KWH, small commercial and industrial customers decreased from 12.8 cents per KWH to 12.1 cents per KWH and rates for medium and large commercial and industrial customers decreased from 11.1 cents per KWH to 10.2 cents per KWH.  Contingent Matters:  The items summarized below contain contingencies that may have an impact on our net income, financial position or cash flows.  See Note 5A, "Commitments and Contingencies - Regulatory Developments and Rate Matters," to the condensed consolidated financial statements for information regarding these matters.  · CTA and SBC Reconciliation:  On March 31, 2009, CL&P filed with the DPUC its 2008 Competitive Transition Assessment (CTA) and Systems Benefit Charge (SBC) reconciliation, which compared CTA and SBC revenues to revenue requirements.  For the 12 months ended December 31, 2008, total CTA revenues exceeded CTA revenue requirements by $84.9 million, which has been recorded as a decrease to the CTA regulatory asset on the accompanying condensed consolidated balance sheet.  For the 12 months ended December 31, 2008, the SBC revenues exceeded SBC cost of service by $2.5 million, which has been recorded as a decrease to the SBC regulatory asset on the accompanying condensed consolidated balance sheet.  We expect a decision in this docket from the DPUC by the end of 2009 and do not expect the outcome to have a material adverse impact on CL&Ps net income or financial position.  · FMCC Filing:  On February 6, 2009, CL&P filed with the DPUC its semi-annual Federally Mandated Congestion Charge (FMCC) filing, which reconciled actual FMCC revenues and charges and generation service charge revenues and expenses, for the period July 1, 2008 through December 31, 2008, and also included the previously filed revenues and expenses for the January 1, 2008 through June 30, 2008 period.  The filing identified an underrecovery for the full year totaling approximately $31.9 million, which has been recorded as a regulatory asset on the accompanying condensed consolidated balance sheets.  The DPUC held a hearing on this filing on April 9, 2009 with a final decision expected in the second quarter of 2009.  We do not expect the outcome of the DPUC's review of this filing to have a material adverse impact on CL&P's net income, financial position or cash flows.  · C2 Prudency Audit:  Pursuant to the decision in CL&P's 2007 rate case, the DPUC has hired a consulting firm to perform a prudency audit of certain costs incurred in the implementation of a new customer service system (C2) at CL&P.  The audit began on December 1, 2008 and is ongoing.  The DPUC intends to open a docket to review the findings of the audit after completion.  We continue to believe that our C2 expenses were prudent and will be recovered in rates.  We do not expect the outcome of the DPUC's review of this audit to have a material adverse impact on CL&P's net income, financial position or cash flows.  59





· ES and SCRC Reconciliation and Rates:On an annual basis, PSNH files with the NHPUC an ES/SCRC reconciliation filing for the preceding year.On May 1, 2009, PSNH filed its 2008 ES/SCRC reconciliation with the NHPUC, whose evaluation includes a prudence review of PSNH's generation activities.  During 2008, ES revenues exceeded ES costs by $20.7 million and SCRC costs exceeded SCRC revenues by $6.4 million resulting in an ES regulatory liability for refunds to customers, and a SCRC regulatory asset for costs that will be recovered from customers.  We do not expect the outcome of the NHPUC review to have a material adverse impact on PSNH's net income or financial position.  · Transition Cost Reconciliation:  On July 18, 2008, WMECO filed its 2007 transition cost (TC) reconciliation with the DPU, which compared TC revenue and revenue requirements.  For the twelve months ended December 31, 2007, total TC revenues along with carrying charges exceeded TC revenue requirements by $2.6 million, which has been recorded as a regulatory liability on the accompanying consolidated balance sheets.  A public hearing and procedural conference was held on November 20, 2008.  On December 22, 2008, the Massachusetts Attorney General filed testimony on two topics: the deferred return and carrying charges on the Capital Project Scheduling List; and the recovery of WMECO's share of Northeast Nuclear Energy Company pension/PBOP costs.  WMECO filed rebuttal testimony on December 30, 2008.  A hearing was held on January 29, 2009.  There is no timeline for a DPU decision.  We do not expect the outcome of the DPU's review of this filing to have a material adverse impact on WMECO's net income, financial position or cash flows.  NU Enterprises Divestitures  We have exited most of our competitive businesses.  NU Enterprises continues to manage to completion its remaining wholesale marketing contracts and to manage its energy services activities.  Wholesale Marketing:During the first quarter of 2009, Select Energy continued to manage its long-term wholesale sales contract with the New York Municipal Power Agency (NYMPA), an agency comprised of municipalities, that expires in 2013, and related supply contracts.  These contracts are derivatives that have been marked to market through earnings.  In addition to the NYMPA portfolio, Select Energy has a non-derivative contract to operate and purchase the output of a certain generating facility in New England through 2012.  As a non-derivative contract, the fair value of this contract has not been reflected on the balance sheet, and the contract has not been marked to market.  Energy Services:  Most of NU Enterprises' energy services businesses were sold in 2005 and 2006.  Certain other businesses were wound down in 2007, and we continue to wind down minimal activity at the other energy services businesses.  However, we continue to own and manage one energy services business, E.S. Boulos Company (Boulos), which is an electrical contractor based in Maine.  NU Enterprises Contracts  Wholesale Derivative Contracts:On January 1, 2008, we implemented SFAS No. 157.  For further information on SFAS No. 157, see Note 3, "Fair Value Measurements," to the condensed consolidated financial statements.  At March 31, 2009 and December 31, 2008, the fair value of NU Enterprises' wholesale derivative liabilities (through its subsidiary Select Energy), which are subject to mark-to-market accounting, are as follows:  (Millions of Dollars)March 31, 2009December 31, 2008Current wholesale derivative liabilities$(6.9)$(14.5)Long-term wholesale derivative liabilities(42.3)(49.4)Portfolio position$(49.2)$(63.9)  Numerous factors could either positively or negatively affect the realization of the wholesale derivative net fair value amounts in cash.  These factors include the volatility of commodity prices until the derivative contracts are exited or expire, differences between expected and actual volumes, the performance of counterparties, and other factors.  Select Energy has policies and procedures requiring all of its wholesale derivative energy positions to be valued daily and segregating responsibilities between the individuals actually transacting (front office) and those confirming the trades (middle office).  The middle office is responsible for determining the portfolio's fair value independent from the front office.  The methods Select Energy used to determine the fair value of its wholesale derivative contracts are identified and segregated in the table of fair value of wholesale derivative contracts at March 31, 2009 and December 31, 2008.  A description of each method is as follows: 1) prices actively quoted primarily represent NYMEX futures and swaps that are marked to closing exchange prices; and 2) prices provided by external sources primarily include over-the-counter forwards and options, including bilateral contracts for the purchase or sale of electricity, and are marked to the mid-point of bid and ask market prices.  The mid-points of market prices are  60





adjusted to include all applicable market information, such as historical experience with intra-month price volatility and exit pricing assumptions.  Currently, a portion of the NYMPA contract's fair value related to intra-month volatility and an exit price premium are determined based upon a model.  For the commodity pricing, broker quotes for electricity prices are available for on-peak and off-peak periods throughout the period of the contract.  Generally, valuations of short-term derivative contracts derived from quotes or other external sources are more reliable should there be a need to liquidate the contracts, while valuations for longer-term derivative contracts are less certain.  Accordingly, there is a risk that derivative contracts will not be realized at the amounts recorded.  The tables below disaggregate the estimated fair value of the wholesale derivative contracts.  Valuations of individual contracts are broken into their component parts based upon prices actively quoted, prices provided by external sources and model-based amounts.  Under SFAS No. 157, contracts are classified in their entirety according to the lowest level for which there is at least one input that is significant to the valuation.  Therefore, these contracts are classified as Level 3 under SFAS No. 157.  At March 31, 2009 and December 31, 2008, the sources of the fair value of wholesale derivative contracts are included in the following tables:  Fair Value of Wholesale Contracts at March 31, 2009(Millions of Dollars)
Sources of Fair ValueMaturity Less
than One YearMaturity of One
to Four YearsMaturity in
Excess
of Four YearsTotal Fair
ValuePrices actively quoted$(5.4)$(13.0)$(1.5)$(19.9)Prices provided by external sources0.4(13.9)(5.3)(18.8)Model-based(1.9)(7.3)(1.3)(10.5)Totals$(6.9)$(34.2)$(8.1)$(49.2)  Fair Value of Wholesale Contracts at December 31, 2008(Millions of Dollars)
Sources of Fair ValueMaturity Less 
than One YearMaturity of One
to Four YearsMaturity in
Excess
of Four YearsTotal Fair
ValuePrices actively quoted$(10.1)$(7.3)$(1.2)$(18.6)Prices provided by external sources(2.7)(21.2)(10.0)(33.9)Model-based (1)(1.7)(6.7)(3.0)(11.4)Totals$(14.5)$(35.2)$(14.2)$(63.9)  (1) The model-based amounts include the effects of implementing SFAS No. 157.  For the three months ended March 31, 2009, the changes in fair value of these contracts are included in the following table:  For the Three Months Ended
March 31, 2009(Millions of Dollars)Total Portfolio Fair ValueFair value of wholesale contracts outstanding at the beginning of the period$(63.9)Contracts realized or otherwise settled during the period (1)9.4Change in unrealized gains included in earnings5.3Fair value of wholesale contracts outstanding at the end of the period$(49.2)  (1) Amount includes purchases, issuances and settlements of $9.2 million and realized intra-month gains of $0.2 million.  For further information regarding Select Energy's derivative contracts, see Note 2, "Derivative Instruments," to the condensed consolidated financial statements.  Counterparty Credit:Counterparty credit risk relates to the risk of loss that Select Energy would incur because of non-performance by counterparties pursuant to the terms of their contractual obligations.  Select Energy has established credit policies with regard to its counterparties to minimize overall credit risk.  These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash advances, LOCs, and parent guarantees), and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  This evaluation results in Select Energy establishing credit limits prior to entering into contracts.  The appropriateness of these limits is subject to our continuing review.  Concentrations among these counterparties may affect Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.  At March 31, 2009, approximately 98 percent of Select Energy's counterparty credit exposure to wholesale counterparties was non-rated, and approximately 2 percent was collateralized.  The bulk of the non-rated credit exposure is comprised of one counterparty, which is a non-rated public entity that we have assessed as creditworthy.  To date, this counterparty has met all of its contractual obligations.  61





Off-Balance Sheet Arrangements  Letters of Credit:  NU provides standby LOCs for the benefit of its subsidiaries under its revolving credit agreement.  PSNH posts such LOCs as collateral with counterparties and ISO-NE.  At March 31, 2009, PSNH had posted $101 million in such NU LOCs, including $10 million with ISO-NE.  In addition, Select Energy had posted a $2 million NU LOC with ISO-NE at March 31, 2009.  Competitive Businesses:  We have various guarantees and indemnification obligations outstanding on behalf of former subsidiaries in connection with the exit from our competitive businesses.  See Note 5C, "Commitments and Contingencies - Guarantees and Indemnifications," to the condensed consolidated financial statements for information regarding the maximum exposure and amounts recorded under these guarantees and indemnification obligations.  Critical Accounting Policies and Estimates Update  The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and at times difficult, subjective or complex judgments.  Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position or results of operations.  Our management communicates to and discusses with our Audit Committee of the Board of Trustees all critical accounting policies and estimates.  The accounting policies and estimates that we believed were the most critical in nature were reported in the 2008 Form 10-K.  There have been no material changes with regard to these critical accounting policies and estimates.  Other Matters  Accounting Standards Issued But Not Yet Adopted:In April 2009, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) FAS 115-2 and FAS 124-2, "Recognition and Presentation of Other-Than-Temporary Impairments," which is effective as of June 30, 2009 with early adoption permitted.  We will adopt the FSP as of June 30, 2009.  The FSP changes the indicators for determining whether an other-than-temporary impairment on a debt security should be recorded in earnings.  Under current accounting guidance, one of the primary indicators that an unrealized loss should be recognized in earnings is if the company does not have the intent and ability to hold a debt security until recovery of its cost basis.  Under the FSP, the primary indicators that an unrealized loss should be recognized in earnings are whether the company intends to sell the debt security or whether it is more likely than not that the company will be required to sell the debt security prior to recovery of its cost basis.  For debt securities determined to be other-than-temporarily impaired, but which the company does not intend to sell or is not more likely than not going to be required to sell before recovery, credit losses are recognized in earnings, and the remaining unrealized losses are recorded in accumulated other comprehensive income.  For other-than-temporarily impaired debt securities that the company intends to sell or is more likely than not going to be required to sell before recovery, all unrealized losses are recorded in earnings.  Implementation of the FSP, which may affect the accounting for debt securities held in our supplemental benefit trust and WMECOs spent nuclear fuel trust, is not expected to have a material effect on the condensed consolidated financial statements.  We will adopt the FSP by applying its provisions to debt securities held in the supplemental benefit trust as of April 1, 2009 through a cumulative effect adjustment to increase retained earnings and a corresponding adjustment to decrease accumulated other comprehensive income.  Beginning in the second quarter of 2009, for debt securities in the supplemental benefit trust that we do not intend to sell or do not expect we will more likely than not be required to sell, we will record credit losses in earnings and other unrealized losses in accumulated other comprehensive income.  Adoption of the FSP for WMECOs spent nuclear fuel trust will not affect shareholders' equity or results of operations due to the regulatory accounting treatment applicable to that trust.  In April 2009, the FASB issued FSP FAS 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly," which is effective prospectively for fair value measurements of assets and liabilities as of June 30, 2009 with early adoption permitted.  The FSP does not change the measurement objective that fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date under current market conditions.  The FSP provides additional guidance on determining whether there has been a significant decrease in the volume and level of activity when compared with normal market activity for an asset or liability and, if so, whether associated transactions or quoted prices are not orderly.  In preparing fair value measurements, reporting entities are required to place more weight on transactions that are orderly than on those that are not orderly.  We will apply the FSP to our fair value measurements of assets and liabilities as of June 30, 2009.  Implementation of the FSP is not expected to have a material effect on our condensed consolidated financial statements.  Forward Looking Statements:This Management's Discussion and Analysis includes statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future 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" through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions.  Forward-  62





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 may 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, actions or inaction by local, state and federal regulatory bodies, changes in business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products and services, changes in weather patterns, changes in laws, regulations or regulatory policy, changes in levels and timing of capital expenditures, disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly, developments in legal or public policy doctrines, technological developments, changes in accounting standards and financial reporting regulations, fluctuations in the value of our remaining competitive electricity positions, actions of rating agencies, and other presently unknown or unforeseen factors.  Other risk factors are detailed from time to time in our reports filed with the SEC and we encourage you to consult such disclosures.  All such factors are difficult to predict, contain uncertainties that may materially affect our actual results and are beyond our control.  You should not place undue reliance on the forward-looking statements, each of which speaks only as of the date on which such statement is made, and we undertake no obligation to update the information contained in 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 Factors," included in this Quarterly Report and in our 2008 Form 10-K.  This Quarterly Report on Form 10-Q and our 2008 Form 10-K also describe material contingencies and critical accounting policies and estimates in the respective "Managements Discussion and Analysis" and "Combined Notes to Consolidated Financial Statements."  We encourage you to review these items.  Web Site:  Additional financial information is available through our web site at www.nu.com.    63





RESULTS OF OPERATIONS - NU CONSOLIDATED  The following table provides the variances in income statement line items for the condensed consolidated statements of income for NU included in this Quarterly Report on Form 10-Q for the three months ended March 31, 2009:  Income Statement Variances
(Millions of Dollars)
2009 over/(under) 2008AmountPercentOperating Revenues$745%Operating Expenses:Fuel, purchased and net interchange power162Other operation(38)(13)Maintenance(8)(14)Depreciation914Amortization of regulatory assets, net(7)(25)Amortization of rate reduction bonds25Taxes other than income taxes1520Total operating expenses(11)(1)Operating Income8564Interest expense, net813Other income, net(10)(69)Income before income tax expense6781Income tax expense28(a)Net income3966Preferred dividends of subsidiary--Net income attributable to controlling interests$3967%  (a) Percent greater than 100.  Net income attributable to controlling interests was $39 million higher in the first quarter of 2009 primarily due the absence of a first quarter 2008 $29.8 million after-tax litigation settlement charge, along with higher regulated distribution and transmission earnings.  Comparison of the First Quarter of 2009 to the First Quarter of 2008  Operating Revenues  For the Three Months Ended March 31,(Millions of Dollars)20092008VarianceElectric distribution$1,245$1,197$48Gas distribution2022002Total distribution1,4471,39750Transmission1288939Regulated companies1,5751,48689Competitive businesses1934(15)NU consolidated$1,594$1,520$74  Operating revenues increased $74 million in 2009 primarily due to higher revenues from the regulated companies ($89 million), partially offset by lower revenues from competitive businesses ($15 million).  The higher regulated companies revenues were primarily due to the recovery of a higher level of CL&P and PSNH distribution related expenses passed through to customers through regulatory tracking mechanisms.  Competitive businesses revenues decreased $15 million primarily due to lower Boulos revenues as a result of lower contractor billings in part due to the economic downturn.  Revenues from the regulated companies increased $89 million due to higher distribution segment revenues ($50 million) and higher transmission segment revenues ($39 million).  Distribution segment revenues increased $50 million primarily due to higher electric distribution revenues ($48 million) and higher gas distribution revenues ($2 million).  Transmission segment revenues increased $39  64





million primarily due to a higher transmission investment base as a result of the completion of our southwest Connecticut projects in 2008.  Electric distribution revenues increased $48 million primarily due to an increase in the portion of electric distribution revenues that does not impact earnings ($33 million) and the component of revenues that does flow through to earnings ($15 million).  The portion of electric distribution segment revenues that flows through to earnings increased $15 million primarily due to increases in CL&P retail rates.  Gas distribution revenues increased $2 million primarily due to higher sales volumes.  Firm natural gas sales increased 12.8 percent in the first three months of 2009 compared with the same period of 2008.  The $33 million increase in electric distribution revenues that does not impact earnings is made up of the components of CL&P, PSNH and WMECO distribution revenues that are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($58 million), partially offset by revenues that are eliminated in consolidation ($25 million).  The distribution revenue tracking components increased $58 million primarily due to higher retail transmission revenues ($43 million) mainly as a result of the higher 2009 rates, higher CL&P delivery-related FMCC ($14 million) and higher recovery of generation service and related congestion charges ($13 million), partially offset by lower CL&P wholesale revenues primarily due to a decrease in the market price of energy related to sales of independent power producers (IPP) generation to ISO-NE ($28 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.  Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expenses increased $16 million in 2009 due to higher costs at the regulated companies ($22 million), partially offset by lower competitive businesses expenses ($6 million).  Fuel expense from the regulated companies increased primarily at CL&P ($21 million) due to an increase in deferred fuel costs primarily due to a lower level of net underrecovery of generation service charge (GSC) and FMCC expenses.  Competitive businesses expenses decreased due to lower Select Energy mark-to-market expenses related to the remaining wholesale marketing contracts, including the 2008 expense associated with the implementation of SFAS No. 157.  Other Operation Other operation decreased $38 million in 2009 primarily due to lower NU parent and other companies expenses ($49 million) and lower competitive businesses expenses ($13 million), partially offset by higher regulated companies distribution and transmission segment expenses ($24 million).  NU parent and other companies' expenses were lower by $49 million in 2009 primarily due to the 2008 $49.5 million payment resulting from the settlement of litigation.  Competitive businesses' expenses were lower by $13 million primarily due to lower Boulos expenses as a result of lower work levels in part due to the economic downturn.  Higher regulated companies' distribution and transmission segment expenses of $24 million are primarily due to higher electric distribution segment expenses ($16 million), higher transmission segment expenses ($4 million) and higher Yankee Gas expenses ($3 million).  Maintenance Maintenance expenses decreased $8 million in 2009 primarily due to lower regulated companies' distribution expenses ($7 million) and lower transmission line, equipment and structure expenses ($1 million).  Distribution expenses were $7 million lower primarily due to lower overhead line maintenance expenses ($16 million) as a result of lower storm-related expenses, partially offset by higher tree trimming ($7 million) and higher PSNH generation expenses that are tracked and recovered through NHPUC approved tracking mechanisms ($1 million).  PSNH and WMECO 2009 storm related expenses were primarily for additional work in the after-math of the December 2008 ice storm that were not recorded in expense, but rather recorded to their respective major storm reserves.  Depreciation Depreciation increased $9 million in 2009 primarily due to higher regulated transmission and distribution plant balances resulting from completed construction programs put into service.  Amortization of Regulatory Assets, Net Amortization of regulatory assets, net decreased $7 million in 2009 for the distribution segment primarily due to lower amortization at CL&P resulting from a lower recovery of transition costs ($13 million), partially offset by higher amortization of SBC ($7 million).  Amortization of Rate Reduction Bonds Amortization of RRBs increased $2 million in 2009.  The higher portion of principal within the RRB payments results in a corresponding increase in the amortization of RRBs.  65





Taxes Other than Income Taxes Taxes other than income taxes increased $15 million in 2009 primarily due to higher Connecticut gross earnings tax ($8 million), mainly as a result of higher CL&P and Yankee Gas revenues that are subject to gross earnings tax, higher payroll taxes ($3 million), and higher property taxes at PSNH and CL&P ($2 million).  Interest Expense, Net Interest expense, net increased $8 million in 2009 primarily due to higher long-term debt interest ($13 million) resulting from the issuance of new long-term debt in 2008 and 2009, partially offset by lower RRB interest resulting from lower principal balances outstanding ($3 million) and lower other interest ($1 million).  Other Income, Net Other income, net decreased $10 million in 2009 primarily due to lower AFUDC equity income ($7 million) as a result of lower eligible CWIP balances and lower Energy Independence Act incentives ($2 million).  Income Tax Expense Income tax expense increased $28 million primarily due to higher pre-tax earnings.    66





THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES  Management's Discussion and Analysis of
Financial Condition and Results of Operations  CL&P is a wholly owned subsidiary of NU.  This discussion should be read in conjunction with NU's Management's Discussion and Analysis of Financial Condition and Results of Operations, condensed consolidated financial statements and footnotes in this Form 10-Q and the 2008 Form 10-K.  RESULTS OF OPERATIONS  The following table provides the variances in income statement line items for the condensed consolidated statements of income for CL&P included in this report on Form 10-Q for the three months ended March 31, 2009:  Income Statement Variances
(Millions of Dollars)
2009 over/(under) 2008AmountPercentOperating Revenues$698%Operating Expenses:Fuel, purchased and net interchange power214Other operation108Maintenance(2)(7)Depreciation819Amortization of regulatory assets, net(7)(34)Amortization of rate reduction bonds37Taxes other than income taxes1124Total operating expenses445Operating Income2528Interest expense, net38Other income, net(9)(78)Income before income tax expense1320Income tax expense631Net Income$715%  Comparison of the First Quarter of 2009 to the First Quarter of 2008  Operating Revenues Operating revenues increased $69 million due to higher transmission segment revenues ($37 million) and higher distribution segment revenues ($32 million).  Transmission segment revenues increased $37 million primarily due to a higher transmission investment base as a result of the completion of our southwest Connecticut projects in 2008.  The distribution segment revenues increased $32 million primarily due to an increase in the portion of distribution revenues that does not impact earnings ($20 million) as a result of the inclusion of distribution revenues in regulatory tracking mechanisms and consolidation eliminations and the component of revenues that flows through to earnings ($12 million).  The $20 million increase in distribution segment revenues that does not impact earnings was primarily due to an increase in the components of retail revenues that are included in DPUC approved tracking mechanisms that track the recovery of certain incurred costs ($38 million), partially offset by consolidation eliminations of transmission segment intracompany billings to the distribution segment ($18 million).  The distribution revenues included in DPUC approved tracking mechanisms increased $38 million primarily due to higher retail transmission revenues ($35 million), delivery-related FMCC ($14 million), an increase in revenues associated with the recovery of GSC and related FMCC ($7 million), partially offset by lower wholesale revenues primarily due to decreased market revenue generated from the sale of CL&Ps IPP generation to ISO-NE due to a decrease in the market price of energy ($28 million).  The higher delivery-related FMCC revenue was primarily due to a larger prior year overrecovery being refunded to customers in 2008 as compared to 2009, partially offset by lower reliability must run costs built into the 2009 rate as compared to 2008.  The higher GSC  67





and related FMCC revenue was primarily due to slightly higher rates due to higher supply prices and higher anticipated congestion costs in 2009 as compared to 2008.  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.  The component of revenues that flows through to earnings increased $12 million primarily as a result of rate changes.  CL&P experienced higher residential sales, which have a higher margin per KWH sold than the commercial and industrial sales, which decreased from 2008.  Retail sales as compared to the same period in 2008 increased 4.7 percent for the residential class and decreased 2.3 percent and 24.1 percent for the commercial and industrial classes, respectively, and total retail sales decreased overall by 1.5 percent.  Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased $21 million primarily due to an increase in deferred fuel costs ($21 million) and GSC supply costs ($8 million), partially offset by lower other purchased power costs ($9 million), all of which are included in DPUC approved tracking mechanisms.  The $21 million increase in deferred fuel costs was primarily due to a lower level of net underrecovery of GSC and FMCC expenses.  The $8 million increase in GSC supply costs was primarily due to slightly higher supply prices in 2009 as compared to 2008.  These GSC supply costs are the contractual amounts CL&P must pay to various suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process.  Other Operation Other operation expenses increased $10 million primarily due to higher distribution segment expenses ($8 million) primarily due to customer account and pension expenses, higher transmission segment expenses ($3 million) and higher costs that are tracked and recovered through distribution tracking mechanisms ($1 million), partially offset by lower consolidation eliminations of transmission segment intracompany billing to the distribution segment ($2 million).  Maintenance Maintenance expenses decreased $2 million in 2009 primarily due to lower distribution overhead lines expenses.  Depreciation Depreciation expense increased $8 million primarily due to higher utility plant balances resulting from completed construction programs put into service.  Amortization of Regulatory Assets, Net Amortization of regulatory assets, net decreased $7 million primarily due to lower amortization related to the recovery of transition charges ($13 million), partially offset by a higher amortization related to the recovery of SBC charges ($7 million).  Amortization of Rate Reduction Bonds Amortization of RRBs increased $3 million.  The higher portion of principal within the RRBs' payment results in a corresponding increase in the amortization of regulatory assets.  Taxes Other Than Income Taxes Taxes other than income taxes increased $11 million primarily due to higher gross earnings taxes as a result of higher distribution and transmission revenues that are subject to gross earnings tax ($7 million), higher payroll taxes ($2 million) and higher property taxes as a result of higher plant balances and higher municipal tax rates ($1 million).  Interest Expense, Net Interest expense, net, increased $3 million primarily due to higher long-term debt interest ($8 million) resulting from the $300 million debt issuance in May 2008 and the $250 million debt issuance in February 2009, partially offset by lower other interest ($3 million) mostly related to the closure of a state income tax audit and lower RRB interest resulting from lower principal balances outstanding ($2 million).  Other Income, Net Other income, net, decreased $9 million primarily due to a lower AFUDC equity income ($7 million) as a result of lower eligible CWIP due to large transmission projects being completed and placed in-service in 2008 and lower capital expenditures in 2009, and lower Energy Independence Act incentives ($2 million).  Income Tax Expense Income tax expense increased $6 million due primarily to higher pre-tax earnings ($4 million) and lower favorable flow through depreciation impacts ($2 million).  68





LIQUIDITY  While the impact of continued market volatility and the extent and impacts of any economic downturn cannot be predicted, we believe that CL&P currently has sufficient operating flexibility and access to funding sources to maintain adequate liquidity (as evidenced by CL&P's issuance of $250 million of 10-year bonds in February 2009 at 5.5 percent).  The credit outlooks for CL&P are all stable.  CL&P has modest risk of calls for collateral due to its business model, as described under "Liquidity-Impact of Financial Market Conditions" in this "Managements Discussion and Analysis of Financial Condition and Results of Operations."  Capital contributions from NU parent and other internal sources of funding are provided to CL&P as necessary.  CL&P does not have any long-term debt maturing until 2014, projected capital expenditures for 2009 of approximately $400 million are significantly less than 2008, and projected operating cash flows for 2009 are higher than 2008.  CL&P had consolidated operating cash flows in the first quarter of 2009 of $74.1 million, compared with $47.8 million in the first quarter of 2008, both after RRB payments included in financing activities.  The increase in first quarter 2009 operating cash flows was primarily due to a decrease in the negative cash flow impact from regulatory refunds and underrecoveries of $60.8 million, partially offset by an increase of $38.2 million in the negative cash flow effect of our accounts payable balances related to operating activities.  We continue to project consolidated operating cash flows at CL&P of approximately $365 million in 2009, after approximately $183 million of RRB payments.  As of March 31, 2009, CL&P had borrowings of $114 million under the $400 million credit facility it shares with other NU subsidiaries, under which it can borrow up to $200 million.  Other financing activities for the first quarter of 2009 included the $250 million bond issuance described above and capital contributions from NU parent of $39 million, offset by $102.7 million in repayment of NU Money Pool borrowings and $28.5 million in common dividends paid to NU parent.  Cash capital expenditures included on the accompanying condensed consolidated statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, the AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.  CL&Ps cash capital expenditures totaled $116.3 million in the first quarter of 2009, compared with $197 million in the first quarter of 2008.  This decrease was primarily the result of lower transmission segment capital expenditures in 2009 due to the completion in 2008 of three major transmission projects in southwest Connecticut.  On April 2, 2009, CL&P completed the remarketing of $62 million of tax-exempt PCRBs it had elected to acquire in October 2008.  The bonds carry a coupon of 5.25 percent until the mandatory tender for purchase on April 1, 2010, and have a final maturity of May 1, 2031.      69





PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES  Management's Discussion and Analysis of Financial Condition and Results of Operations  PSNH is a wholly owned subsidiary of NU.  This discussion should be read in conjunction with NU's Management's Discussion and Analysis of Financial Condition and Results of Operations, condensed consolidated financial statements and footnotes in this Form 10-Q and the 2008 Form 10-K.  RESULTS OF OPERATIONS  The following table provides the variances in income statement line items for the condensed consolidated statements of income for PSNH included in this report on Form 10-Q for the three months ended March 31, 2009:  Income Statement Variances
(Millions of Dollars)
2009 over/(under) 2008AmountPercentOperating Revenues$165%Operating Expenses:Fuel, purchased and net interchange power43Other operation918Maintenance(4)(22)Depreciation212Amortization of regulatory assets, net224Amortization of rate reduction bonds--Taxes other than income taxes222Total operating expenses156Operating Income14Interest expense, net--Other income, net--Income before income tax expense13Income tax expense--Net Income$15%  Comparison of the First Quarter of 2009 to the First Quarter of 2008  Operating Revenues Operating revenues increased $16 million in 2009 due to higher distribution segment revenues ($15 million) and higher transmission segment revenues ($1 million).  The distribution segment revenues increased $15 million primarily due to an increase in the portion of electric distribution revenues that does not impact earnings ($13 million) as a result of the inclusion of distribution revenues in regulatory tracking mechanisms and consolidation eliminations of transmission segment intracompany billings to the distribution segment.  The component of revenues that flows through to earnings increased $2 million primarily as a result of rate changes.  PSNH experienced higher residential sales in 2009, which have a higher margin per KWH sold than the commercial and industrial sales, which decreased from 2008.  Retail sales as compared to the same period in 2008 increased 3.1 percent for the residential class and decreased 1.5 percent and 8.0 percent for the commercial and industrial classes, respectively and total retail sales decreased overall by 0.7 percent.  The $13 million increase in distribution revenues that does not impact earnings is due to the portion of retail revenues that are included in NHPUC approved tracking mechanisms that track the recovery of certain incurred costs ($18 million), partially offset by revenues that are eliminated in consolidation ($5 million).  The distribution revenues included in NHPUC approved tracking mechanisms increased $18 million primarily due to the pass-through of higher energy supply costs ($5 million), an increase in the SCRC ($5 million), higher retail transmission revenues ($4 million), higher Northern Wood Power Plant renewable energy certificate revenues ($3 million) and higher wholesale revenues ($2 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.   70





Transmission segment revenues increased $1 million primarily due to a higher transmission investment base.  Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power costs increased $4 million primarily due to higher forward energy market prices, partially offset by a decrease in payments to higher priced IPPs in 2008 as contracts expired.  Other Operation Other operation expenses increased $9 million due to higher distribution segment expenses ($8 million) primarily due to higher administrative and general expenses including higher pension expense, higher generation business costs that are tracked and recovered through distribution tracking mechanisms ($2 million) and higher transmission segment expenses ($1 million).  Maintenance Maintenance expenses decreased $4 million primarily due to lower storm costs.   The decrease in 2009 storm-related expenses was primarily related to additional work in the aftermath of the December 2008 ice storm that was not recorded to expense, but rather to the storm reserve.  Depreciation Depreciation expense increased $2 million primarily due to higher utility plant balances resulting from completed construction programs put into service.  Amortization of Regulatory Assets, Net Amortization of regulatory assets, net increased $2 million primarily due to an increase in net deferrals associated with PSNHs ES, transmission cost adjustment mechanism (TCAM) and SCRC tracking mechanisms.  Taxes Other Than Income Taxes Taxes other than income taxes increased $2 million primarily due to higher property taxes as a result of higher net plant balances and higher local municipal tax rates ($1 million) and higher payroll taxes ($1 million).  LIQUIDITY  PSNH had consolidated operating cash flows in the first quarter of 2009 of $0.8 million, compared with $35.2 million in the first quarter of 2008, both after RRB payments.  The decrease in first quarter 2009 operating cash flows was primarily due to an increase of $68.1 million in the negative cash flow effect of accounts payable balances primarily as a result of costs related to the major storm in December 2008 that were paid to vendors in the first quarter of 2009 and deferred and expected to be recovered from customers beginning in the second half of 2009.  This negative cash flow impact was partially offset by a decrease in the negative cash flow impact from various other working capital items, such as accrued income taxes.     71





WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY  Management's Discussion and Analysis of
Financial Condition and Results of Operations  WMECO is a wholly owned subsidiary of NU.  This discussion should be read in conjunction with NU's Management's Discussion and Analysis of Financial Condition and Results of Operations, condensed consolidated financial statements and footnotes in this Form 10-Q and the 2008 Form 10-K.  RESULTS OF OPERATIONS  The following table provides the variances in income statement line items for the condensed consolidated statements of income for WMECO included in this report on Form 10-Q for the three months ended March 31, 2009:  Income Statement Variances
(Millions of Dollars)
2009 over/(under) 2008AmountPercentOperating Revenues$22%Operating Expenses:Fuel, purchased and net interchange power12Other operation419Maintenance(1)(32)Depreciation--Amortization of regulatory assets, net(2)(76)Amortization of rate reduction bonds--Taxes other than income taxes--Total operating expenses22Operating Income--Interest expense, net--Other income, net--Income before income tax expense--Income tax expense--Net Income$--%  Comparison of the First Quarter of 2009 to the First Quarter of 2008  Operating Revenues Operating revenues increased $2 million in 2009 due to higher distribution segment revenues ($2 million) and higher transmission segment revenues ($1 million).  The distribution segment revenues increased $2 million primarily due to the component of revenues that flows through to earnings, mainly due to the distribution rate changes effective January 1, 2009.  The rate changes were a result of an increase in residential customer rates, being partially offset by a decrease in commercial and industrial customer rates.  In addition, WMECO experienced higher residential sales, which have a higher margin per KWH sold than the commercial and industrial sales, which decreased in 2009.  Retail sales as compared to the same period in 2008 increased 1.9 percent for the residential class and decreased 3.1 percent and 16 percent for the commercial and industrial classes, respectively.  Total retail sales decreased overall by 3.2 percent.  Transmission segment revenues increased $1 million primarily due to a higher transmission investment base.  Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased $1 million primarily due to higher basic service supply costs.  The basic service supply costs are the contractual amounts we must pay to various suppliers that serve basic service load after winning a competitive solicitation process.   72





Other Operation Other operation expenses increased $4 million primarily due to higher retail transmission costs that are tracked and recovered through distribution tracking mechanisms ($3 million).  Maintenance Maintenance expenses decreased $1 million primarily due to lower storm cost expenses ($2 million), partially offset by higher tree trimming expenses ($1 million).  The decrease in 2009 storm-related expenses was primarily related to additional work in the aftermath of the December 2008 ice storm that was not recorded to expense, but rather to the storm reserve.  Amortization of Regulatory Assets, Net Amortization of regulatory assets, net decreased $2 million in 2009 primarily due to the deferral of allowed transition costs that are in excess of transition revenues, resulting mainly from a decrease in the TC component rate.  LIQUIDITY  WMECO had negative consolidated operating cash flows in the first quarter of 2009 of $11.6 million, compared with positive operating cash flows of $1.8 million in the first quarter of 2008, both after RRB payments.  The decrease in first quarter 2009 operating cash flows was primarily due to an increase of $19.4 million in the negative cash flow effect of accounts payable balances partially as a result of costs related to the major storm in December 2008 that were paid to vendors in the first quarter of 2009 and deferred and expected to be recovered from customers in future years.  This cash flow impact was partially offset by a decrease of approximately $7 million in the negative cash flow impact from accrued income taxes.    73





ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK  Market Risk Information  Commodity Price Risk Management:  We have no contracts entered into for trading purposes.  Our regulated companies enter into energy contracts to serve our customers, and the economic impacts of those contracts are passed on to our customers.  Accordingly, the regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments, and the sensitivity analyses below do not include these contracts.  The wholesale portfolio held by Select Energy includes contracts that are market-risk sensitive, including a wholesale sales contract with NYMPA through 2013 with approximately 0.2 million remaining MWH of sales volume, net of related supply contracts.Select Energy also has a contract that expires in 2012 to purchase output from a generation facility.  As Select Energy's contract volumes are winding down, and as the NYMPA contract is substantially hedged against price risks, we have somewhat limited exposure to commodity price risks.  For Select Energys wholesale portfolio, we utilize the sensitivity analysis methodology to disclose quantitative information for our commodity price risks (including where applicable capacity and ancillary components).  Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from our market risk-sensitive contracts over a selected time period due to one or more hypothetical changes in commodity price components, or other similar price changes.  Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity components, contract prices and market prices represented by each derivative contract.  For swaps, forward contracts and options, fair value reflects our best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments.  Exchange-traded futures and options are recorded at fair value based on closing exchange prices.  A portion of the fair value of the NYMPA contract is based on a model.  The fair value of the generation purchase contract is based on a model using available market information.  Select Energys Wholesale Portfolio: When conducting sensitivity analyses of the change in the fair value of the wholesale portfolio, which includes several derivative contracts and a non-derivative power purchase contract, which would result from a hypothetical change in the future market price of electricity, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments.  A hypothetical change in the fair value of the wholesale portfolio was determined assuming a 10 percent change in forward market prices.  At March 31, 2009, we calculated the market price resulting from a 10 percent change in forward market prices.  A 10 percent increase in prices for all products would have resulted in a pre-tax increase in fair value of $6.2 million and a 10 percent decrease in prices for all products would have resulted in a pre-tax decrease in fair value of $6.8 million.  A 10 percent increase in energy prices would have resulted in a $0.2 million pre-tax decrease in fair value, and a 10 percent decrease in energy prices would have resulted in a $0.4 million pre-tax decrease in fair value.  A 10 percent increase/(decrease) in capacity prices would have resulted in a $1.1 million pre-tax increase/(decrease) in fair value.  A 10 percent increase/(decrease) in ancillary prices would have resulted in a $5.3 million pre-tax increase/(decrease) in fair value.  At December 31, 2008, we calculated the market price resulting from a 10 percent change in forward market prices.  A 10 percent increase in prices for all products would have resulted in a pre-tax increase in fair value of $5.6 million, and a 10 percent decrease in prices for all products would have resulted in a pre-tax decrease in fair value of $6.1 million.  A 10 percent increase in energy prices would have resulted in a $1 million pre-tax decrease in fair value, and a 10 percent decrease in energy prices would have resulted in a $0.5 million pre-tax increase in fair value.  A 10 percent increase/(decrease) in capacity prices would have resulted in a $1.2 million pre-tax increase/(decrease) in fair value.  A 10 percent increase/(decrease) in ancillary prices would have resulted in a $5.4 million pre-tax increase/(decrease) in fair value.  The impact of a change in electricity prices on wholesale transactions at March 31, 2009 are not necessarily representative of the results that will be realized if such a change were to occur.  Energy, capacity and ancillaries have different market volatilities.  The method we use to determine the fair value of these contracts includes discounting expected future cash flows using a LIBOR swap curve.  As such, the wholesale portfolio is also exposed to interest rate volatility.  This exposure is not modeled in sensitivity analyses, and we do not believe that such exposure is material.  The derivative contracts in the wholesale portfolio are accounted for at fair value, and changes in market prices impact earnings.  Other Risk Management Activities  Interest Rate Risk Management: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt.  At March 31, 2009, approximately 92 percent (87 percent including the long-term debt subject to the fixed-to-floating interest rate swap as variable rate long-term debt) of our long-term debt, including fees and interest due for spent nuclear fuel disposal costs, was at a fixed interest rate.  The remaining long-term debt is at variable interest rates and is subject to interest rate risk that could result in earnings volatility.  Assuming a one percentage point increase in our variable  74





interest rate, annual interest expense would have increased by a pre-tax amount of $3.3 million.  At March 31, 2009, we maintained a fixed-to-floating interest rate swap at NU parent to manage the interest rate risk associated with $263 million of its fixed-rate long-term debt.  Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations.  We serve a wide variety of customers and suppliers that include IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers.  Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts.  This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.  Credit risks and market risks at NU Enterprises are monitored regularly by a Risk Oversight Council.  The Risk Oversight Council is comprised of individuals from outside of the management of these activities that create these risk exposures and functions to ensure compliance with our stated risk management policies.  We track and re-balance the risk in our portfolio in accordance with fair value and other risk management methodologies that utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure.  The NYMEX traded futures and option contracts cleared off the NYMEX exchange are ultimately guaranteed by NYMEX to Select Energy.  Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk on all types of transactions.  These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash in advance, LOCs, and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty in the extent of default.  This evaluation results in establishing credit limits prior to Select Energy entering into energy contracts.  The appropriateness of these limits is subject to continuing review.  Concentrations among these counterparties may impact Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions.  At March 31, 2009 and December 31, 2008, Select Energy had cash collateral balances deposited with its NYMEX broker of $35.7 million and $26.3 million, respectively, which is included in current assets - prepayments and other on the accompanying condensed consolidated balance sheets.  Select Energy held no collateral balances from counterparties at either period end.  In addition, Select Energy had posted a $2 million NU LOC at March 31, 2009 in favor of ISO-NE.  Our regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies.  Our regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and maintain an oversight group that monitors contracting risks, including credit risk.  At March 31, 2009, CL&P had $1 million in cash collateral deposited with counterparties.  At December 31, 2008, our regulated companies neither held cash collateral nor deposited collateral with counterparties.  NU provides standby LOCs for the benefit of its subsidiaries under its revolving credit agreement.  PSNH posts such LOCs as collateral with counterparties and ISO-NE.  At March 31, 2009, PSNH had posted $101 million in such NU LOCs.  We have implemented an Enterprise Risk Management (ERM) methodology for identifying the principal risks of the company.  ERM involves the application of a well-defined, enterprise-wide methodology that will enable our Risk and Capital Committee, comprised of our senior officers, to oversee the identification, management and reporting of the principal risks of the business.  However, there can be no assurances that the ERM process will identify every risk or event that could impact our financial condition or results of operations.  The findings of this process are periodically discussed with our Board of Trustees.  Additional quantitative and qualitative disclosures about market risk are set forth in Part I, Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," included in this Quarterly Report on Form 10-Q.   ITEM 4. CONTROLS AND PROCEDURES  Management, on behalf of NU, CL&P, PSNH, and WMECO, evaluated the design and operation of the disclosure controls and procedures at March 31, 2009 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC.  This evaluation was made under managements supervision and with managements participation, including the principal executive officers and principal financial officer as of the end of the period covered by this report on Form 10-Q.  There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures.  Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control  75





objectives.  The principal executive officers and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of NU, CL&P, PSNH, and WMECO are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.  There have been no changes in internal controls over financial reporting for NU, CL&P, PSNH, and WMECO during the quarter ended March  31, 2009 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.   76





PART II.  OTHER INFORMATION   ITEM 1. LEGAL PROCEEDINGS  We are parties to various legal proceedings.  We have identified these legal proceedings in Part I, Item 3, "Legal Proceedings," and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2008, which disclosures are incorporated herein by reference.  There have been no additional legal proceedings identified and no material changes with regard to the legal proceedings previously disclosed in our most recent Form 10-K.   ITEM 1A. RISK FACTORS  We are subject to a variety of significant risks in addition to the matters set forth under "Forward Looking Statements," in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Matters," of this Quarterly Report on Form 10-Q.  We have identified a number of these risk factors in our Annual Report on Form 10-K for the year ended December 31, 2008, which risk factors are incorporated herein by reference.  These risk factors should be considered carefully in evaluating our risk profile.  Other than as set forth below, there have been no additional risk factors identified and no material changes with regard to the risk factors previously disclosed in our most recent Annual Report on Form 10-K.  Market performance or changes in assumptions could require us to make significant contributions to our pension and PBOP plans.  We provide a defined benefit pension plan and other post-retirement benefits for a substantial number of employees, former employees and retirees.  At January 1, 2008, our pension plans funded ratio (the value of plan assets divided by the funding target in accordance with the requirements of the Pension Protection Act) was 111 percent.  As a result of adverse market returns on investments in 2008 due to negative financial market conditions, the pension plans projected funded ratio had declined to an estimated 77 percent at January 1, 2009.  As a result, while we are not required to make contributions to the pension plan in 2009, we may be required to make an aggregate contribution of $300 million to $350 million in 2010, beginning in the second quarter of 2010 and additional contributions in subsequent years.  Various factors, including continued declines in financial markets, could increase the amount of contributions required to fund our pension plan in the future.  Funding requirements of this magnitude, when combined with the financing requirements of our construction program, could impact the timing and amount of future equity and debt financings and would negatively affect our financial position, cash flows and results of operations.  See "Liquidity - Impact of Financial Market Conditions" in our "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this Quarterly Report on Form 10-Q for more information.  The measurement of our expected future pension obligations, costs and liabilities is also highly dependent on a variety of assumptions, most of which relate to factors beyond our control.  These assumptions include investment returns, interest rates, health care cost trends, benefit improvements, salary increases and the demographics of plan participants.  For example, changes in interest rates affect the liabilities under the pension plan; as interest rates decrease, the liabilities increase, potentially increasing the funding requirements.  If our assumptions prove to be inaccurate, our future costs could increase significantly.   ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS  There were no purchases made by or on behalf of NU or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934) of common shares during the quarter ended March 31, 2009.     77





ITEM 6. EXHIBITS  Each document described below is incorporated by reference by the registrant(s) listed to the files identified, unless designated with a (*), which exhibits are filed herewith.  Exhibit No. Description  Listing of Exhibits (NU)  *12 Ratio of Earnings to Fixed Charges  *15 Deloitte & Touche LLP Letter Regarding Unaudited Financial Information  *31 Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 8, 2009  *31.1 Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 8, 2009  *32 Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities and David R. McHale, Executive Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 8, 2009  Listing of Exhibits (CL&P)  4 Series A Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee, dated as of February 1, 2009 to Indenture and Mortgage and Deed of Trust dated as of May 1, 1921, as amended and restated as of April 7, 2005 (incorporated by reference to Exhibit 4 to Current Report on Form 8-K filed February 19, 2009 (File No. 0-00404).  *12 Ratio of Earnings to Fixed Charges  *31 Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 8, 2009  *31.1 Certification of David R. McHale, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 8, 2009  *32 Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company and David R. McHale, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 8, 2009  Listing of Exhibits (PSNH)  *12 Ratio of Earnings to Fixed Charges  *31 Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 8, 2009  *31.1 Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 8, 2009   78





*32 Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire and David R. McHale, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 8, 2009  Listing of Exhibits (WMECO)  *12 Ratio of Earnings to Fixed Charges  *31 Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 8, 2009  *31.1 Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 8, 2009  *32 Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company and David R. McHale, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 8, 2009    79





SIGNATURE   Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.   NORTHEAST UTILITIES(Registrant)     By/s/
David R. McHaleDateDavid R. McHaleExecutive Vice President and Chief Financial OfficerMay 8, 2009(for the Registrant and as Principal Financial Officer)   ____________________________________________________________________________________ SIGNATURE   Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.   THE CONNECTICUT LIGHT AND POWER COMPANY(Registrant)     By/s/
David R. McHaleDateDavid R. McHaleExecutive Vice President and Chief Financial OfficerMay 8, 2009(for the Registrant and as Principal Financial Officer)   80





SIGNATURE   Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.   PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE(Registrant)     By/s/
David R. McHaleDateDavid R. McHaleExecutive Vice President and Chief Financial OfficerMay 8, 2009(for the Registrant and as Principal Financial Officer)   ____________________________________________________________________________________ SIGNATURE   Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.    WESTERN MASSACHUSETTS ELECTRIC COMPANY(Registrant)     By/s/
David R. McHaleDateDavid R. McHaleExecutive Vice President and Chief Financial OfficerMay 8, 2009(for the Registrant and as Principal Financial Officer)    81