CONNECTICUT LIGHT & POWER CO - Annual Report: 2004 (Form 10-K)

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

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Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

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.

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [Ö]

Indicate by check mark whether the registrants are accelerated filers (as defined in Rule 12b-2 of the Act).

The aggregate market value of Northeast Utilities' Common Shares, $5.00 Par Value, held by nonaffiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of Northeast Utilities' most recently completed second fiscal quarter (June 30, 2004) was $2,494,074,290 based on a closing sales price of $19.47 per share for the 128,098,320 common shares outstanding on June 30, 2004.  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.

Documents Incorporated by Reference:

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GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations or acronyms that are found in this report:

COMPANIES

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GENERATING UNITS

REGULATORS

OTHER

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NORTHEAST UTILITIES

THE CONNECTICUT LIGHT AND POWER COMPANY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

WESTERN MASSACHUSETTS ELECTRIC COMPANY

2004 Form 10-K Annual Report
Table of Contents

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NORTHEAST UTILITIES

THE CONNECTICUT LIGHT AND POWER COMPANY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

WESTERN MASSACHUSETTS ELECTRIC COMPANY

PART I

Item 1.

Business

The Northeast Utilities System

Northeast Utilities (NU) is the parent company of the Northeast Utilities system (the NU system).  The NU system furnishes franchised retail electric service to approximately 1.9 million customers in 419 cities and towns in Connecticut, New Hampshire and western Massachusetts through three of NU's wholly-owned subsidiaries (The Connecticut Light and Power Company [CL&P], Public Service Company of New Hampshire [PSNH] and Western Massachusetts Electric Company [WMECO]).

The NU system also furnishes franchised retail natural gas service in a large part of Connecticut through Yankee Gas Services Company (Yankee Gas), a subsidiary of Yankee Energy System, Inc. (Yankee), the largest natural gas distribution company in Connecticut.  Yankee Gas serves approximately 194,000 residential, commercial and industrial customers in 71 cities and towns in Connecticut, including large portions of the central and southwest sections of the state.  

NU, through its wholly-owned subsidiary, NU Enterprises, Inc. (NUEI), owns a number of competitive energy and related businesses, including Northeast Generation Company (NGC), Northeast Generation Services Company (NGS), Select Energy, Inc. (Select Energy), Select Energy Services, Inc. (SESI), Mode 1 Communications, Inc. (Mode 1) and Woods Network Services, Inc. (Woods Network).  Holyoke Water Power Company (HWP), a subsidiary of NU, is a resource of NUEI through an output contract with Select Energy.  For information regarding the activities of these subsidiaries, see "Competitive System Businesses."

Several other wholly-owned subsidiaries of NU provide support services for the NU system companies and, in some cases, for other New England utilities.  Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, information technology, engineering, financial, legal, operational, planning, purchasing and other services to the NU system companies.  Three other subsidiaries construct, acquire or lease some of the property and facilities used by the NU system companies.

The NU system is regulated in virtually all aspects of its business by various federal and state agencies, including the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC) and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each company operates, including the Connecticut Department of Public Utility Control (DPUC), the New Hampshire Public Utilities Commission (NHPUC) and the Massachusetts Department of Telecommunications and Energy (DTE).  In recent years, there has been significant legislative and regulatory activity changing the nature of regulation of the industry.  For more information regarding these restructuring initiatives, see "Regulated Electric Operations."

For information regarding each of the NU system’s reportable segments, see Footnote 15, "Segment Information" contained within NU’s 2004 Annual Report to Shareholders, which is incorporated into this Form 10-K by reference.

SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES

LITIGATION REFORM ACT OF 1995

In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 (Reform Act), NU and its reporting subsidiaries are hereby filing cautionary statements identifying important factors that could cause NU or its subsidiaries' actual results to differ materially from those projected in forward looking statements (as such term is defined in the Reform Act) made by or on behalf of NU or its subsidiaries in this combined Form 10-K, in any subsequent filings with the SEC, in presentations, in response to questions, or otherwise.  Any statements that express or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events, or performance (often, but not always, through the use of words or phrases such as estimate, expect, anticipate, intend, plan, believe, forecast, should, could and similar expressions) are not statements of historical facts and may be forward looking.  Forward looking statements involve estimates, assumptions and uncertainties that could cause actual results to differ materially from those expressed in the forward looking statements.  Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause NU or its subsidiaries' actual results to differ materially from those contained in forward looking statements of NU or its subsidiaries made by or on behalf of NU or its subsidiaries.

Any forward looking statement speaks only as of the date on which such statement is made, and NU and its subsidiaries undertake no obligation to update any forward looking statement or statements to reflect events or circumstances after the date on which such

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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.

Some important factors that could cause actual results or outcomes to differ materially from those discussed in the forward looking statements include, but are not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, expiration or initiation of significant energy supply contracts, changes in levels of capital expenditures, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, effectiveness of NU’s risk management policies and procedures, changes in accounting standards and financial reporting regulations, fluctuations in the value of electricity positions, changes in the ability to sell electricity positions and close out natural gas positions at anticipated margins, obtaining new contracts at anticipated volumes and margins, terrorist attacks on domestic energy facilities, and other presently unknown or unforeseen factors.  Other risk factors are detailed from time to time in NU’s reports to the SEC.

All such factors are difficult to predict, contain uncertainties which may materially affect actual results and are beyond the control of NU or its subsidiaries.

RISK FACTORS

NU is subject to a variety of significant risks in addition to the matters set forth under “Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995” above.  Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks.  These risk factors should be considered carefully in evaluating our risk profile.

Risks Related to Disposition of Wholesale Competitive and Services Businesses

On March 9, 2005, NU announced that it completed its previously announced comprehensive review of its competitive energy businesses and that it had decided that NUEI will exit the wholesale marketing business.  NU has concluded that the wholesale merchant energy sector in the power pools between Maine and Maryland is becoming increasingly competitive and that NUEI’s wholesale marketing business will be unable to attain the profit margins necessary to generate acceptable returns and cash flows.  As a result, NUEI will explore a number of alternatives for exiting the wholesale marketing business, including selling the wholesale marketing franchise, selling existing contracts, restructuring longer term contracts and allowing shorter term contracts to expire without being renewed.  NUEI’s marketing subsidiary, Select Energy, will only bid on new full requirements wholesale contracts to improve the value of its book of business by reducing existing electric positions.

NU also concluded that NUEI’s competitive energy services business are not central to NU’s long-term strategy and do not meet the company’s expectations of profitability.  As a result, NU will explore ways to divest those businesses in a manner that maximizes their value.  Those businesses include electrical, mechanical, telecommunications, commercial plumbing and performance contracting companies.  NU will retain its competitive generation and retail energy marketing businesses because it believes that the assets and retail business are competitively positioned to create significant opportunities for those businesses over the next several years.

NU will retain its 1,443 megawatts of competitive generating assets because it expects that their value could increase significantly in the coming years.  The competitive generating assets, which include pumped storage, hydroelectric and coal-fired units, are contained within NGC and HWP.  NUEI also will retain NGS, which operates the NGC and HWP plants.

NU expects to record a charge in the first quarter of 2005 associated with the wholesale marketing and energy services businesses.  The level of that charge will depend on a number of factors, including how the disposition of those businesses is accomplished.  NU continues to work with the firm of Lazard Freres & Co., LLC on that process.

While the energy services businesses present a lower level of volatility and risk, the wholesale business, until disposed of, will continue to present financial risk to NU from a variety of perspectives.  These include earnings volatility around Select Energy’s portfolio of gas and electric resources procured to serve both existing and anticipated load: with the decision to dispose of this business, certain contracts within the portfolio will be accounted for on a mark to market, rather than accrual, basis. The earnings charge which NU expects to take referred to above may not be adequate to cushion future negative price movements which may occur. In addition, Select Energy’s ability to function will continue to be dependant upon the financial reliability of its counterparties and its ability to manage its wholesale marketing portfolio of contracts and assets within acceptable risk parameters.

Risks Related to Retained Retail Competitive and Generation Businesses

The retail competitive energy business presents the same kinds of challenges as the wholesale competitive energy businesses but on a smaller scale.  Select Energy generally acquires retail customers in smaller increments, which while requiring careful sourcing allows

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energy assets to be acquired in smaller increments with less risk. However, fluctuations in prices, fuel costs, competitive conditions, regulations, weather, transmission costs, lack of market liquidity, plant outages and other factors can all impact the retail business adversely from time to time.

The competitive generation business is also subject to these risks. In addition, the future value of LICAP credits have not been determined and are subject to regulatory decision-making over which NU has no control.  

Risks Associated With The Transmission and Distribution Operations Of NU’s Utility Subsidiaries

Transmission.

NU, primarily through its subsidiary CL&P, has undertaken a substantial transmission capital investment program over the past several years and expects to invest more than $1.5 billion in regulated electric transmission infrastructure from 2005 through 2009.  Included in this amount is approximately $1.4 billion for costs associated with construction of two Connecticut 345 KV transmission lines from Norwalk to Middletown and Norwalk to Bethel; replacement of an undersea electric transmission line between Norwalk and Northport, New York; and two 115 KV underground transmission lines between Norwalk and Stamford, Connecticut.  The regulatory approval process for these transmission projects has encompassed an extensive permitting, design and technical approval process.  Various factors have resulted in increased cost estimates and delayed construction.  

The projects are expected to help alleviate identified reliability issues in southwest Connecticut and to help reduce customers’ costs in all of Connecticut.  However, if, due to further regulatory or other delays, the projected in-service date for one or more of these projects is delayed, there may be increased risk of failures in the existing electricity transmission system in southwestern Connecticut and supply interruptions or blackouts may occur.  

The successful implementation of NU’s transmission construction plans is also subject to the risk that new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations could impact NU’s ability to meet its construction schedule and/or require NU to incur additional expenses, and may adversely affect its ability to achieve forecast levels of revenues.

Unless CL&P is able to increase rates to recover these construction costs on a timely basis, certain of NU’s and CL&P’s financial ratios may decline and CL&P’s ability to pay dividends to NU to support its common dividend and interest requirements may be weakened.

Distribution.

CL&P and WMECO procure energy for a substantial portion of their customers via requests for proposal on an annual, semi-annual or quarterly basis.  There is a risk at any given solicitation that the solicitation will not be fully subscribed or that prices will be much higher than current prices.  CL&P and WMECO receive approvals of recovery of these contract prices from the DPUC and DTE, respectively.  While both regulators have consistently approved solicitation processes, results and recovery of costs, management cannot predict the outcome of future solicitation efforts or the regulatory proceedings related thereto.

Litigation-Related Risks

NU and its affiliates are engaged in litigation that could result in the imposition of large cash awards against them.  This litigation includes civil lawsuits between Consolidated Edison, Inc. (Con Edison) and NU relating to the parties’ October 13, 1999 Agreement and Plan of Merger and the termination of a decommissioning contract between the Connecticut Yankee Atomic Power Company (CYAPC), the stock of which is 49 percent owned by subsidiaries of NU, and Bechtel Power Corporation.  

Further information regarding these legal proceedings, as well as other matters, is set forth in Item 3, "Legal Proceedings."

NU may also be subject to future litigation based on asserted or unasserted claims and cannot predict the outcome of any of these proceedings.  Adverse outcomes in existing or future litigation could result in the imposition of substantial cash damage awards against us.

Risks Associated With Environmental Regulation

NU’s subsidiaries’ operations are subject to extensive federal, state and local environmental statutes, rules and regulations which regulate, among other things, air emissions, water discharges and the management of hazardous and solid waste.  Compliance with these requirements requires NU to incur significant costs relating to environmental monitoring, installation of pollution control equipment, emission fees, maintenance and upgrading of facilities, remediation and permitting.  The costs of compliance with these legal requirements have been significant in the past and may increase in the future.  If such costs do increase, this could have an adverse impact on NU’s business and results of operations, financial position and cash flows.  

If NU fails to comply with environmental laws and regulations, even if due to factors beyond its control or reinterpretations of existing requirements, such failure may also lead to the assessment of civil and/or criminal liability and fines.  

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Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to NU.  Revised or additional laws could result in significant additional expense and operating restrictions on NU’s facilities or increased compliance costs which may not be fully recoverable in rates.  The cost impact of any such legislation would be dependent upon the specific requirements adopted and cannot be determined at this time.

REGULATED ELECTRIC OPERATIONS

Distribution and Sales

CL&P, PSNH and WMECO furnish retail franchise electric service in 149, 211 and 59 cities and towns in Connecticut, New Hampshire and Massachusetts, respectively.  In December 2004, CL&P provided retail franchise service to approximately 1.2 million customers in Connecticut, PSNH provided retail service to approximately 475,000 customers in New Hampshire and WMECO served approximately 207,000 retail customers in Massachusetts.

The following table shows the sources of 2004 electric franchise retail revenues based on categories of customers:

The actual changes in retail kWh sales for the last two years and the forecasted retail sales growth estimates for the five-year period 2004 through 2009 for CL&P, PSNH and WMECO are set forth below:

Consolidated NU retail sales rose by 0.9 percent in 2004, compared with 2003.  Residential electric sales were up 0.3 percent. Commercial sales were up by 1.7 percent for the year and industrial sales increased by 0.8 percent.  Retail sales for CL&P, WMECO and PSNH were up 0.1 percent, 1.6 percent and 3.1 percent, respectively.

Regional and System Coordination

The NU electric utility subsidiaries and most other New England utilities are parties to an agreement (the Restated NEPOOL Agreement) which provides for coordinated planning and operation of the region's generation and transmission facilities.  The Restated NEPOOL Agreement provides for (i) a pool-wide open access transmission tariff; (ii) the creation of an ISO; and (iii) a broader governance structure for the New England Power Pool (NEPOOL) and a more open, competitive market structure.  Under these arrangements, ISO New England Inc. (ISO-NE), a non-profit corporation whose board of directors and staff are not controlled by or affiliated with market participants, ensures the reliability of the NEPOOL transmission system, administers the NEPOOL tariff and oversees the efficient and competitive functioning of the regional power market.

The NEPOOL tariff provides for nondiscriminatory open access to the regional transmission network at a single rate regardless of transmitting distance for all transactions.  The rate is a formula rate, structured to ensure that each transmission provider under the NEPOOL tariff recovers its revenue requirements.

Open access transmission service over local transmission networks is provided by individual local transmission owners through their respective open access transmission tariffs.  NU’s local open access transmission tariff (Tariff No. 10) is also a formula rate which was recently restructured to ensure timely recovery of NU’s revenue requirements.  As a result of the comprehensive settlement in 2004 of certain issues concerning Tariff No. 10, NU’s return on equity (ROE) for recovery of transmission revenue requirements cost was set at 11 percent, until such time as the FERC establishes an ROE for the regional transmission organization (RTO) tariff discussed below.

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Transmission revenues are allocated between CL&P, HWP and its wholly-owned subsidiary, Holyoke Power and Electric Company (HP&E), WMECO and PSNH based upon a net revenue requirement allocation methodology.  These companies are currently pursuing FERC approval of the net revenue allocation methodology.

Transmission Access and FERC Regulatory Changes

NU’s electric utility subsidiaries’ wholesale transmission revenues are based on rates and formulas that are approved by the FERC.  Most of NU’s wholesale transmission revenues are collected through a combination of the New England regional network service (RNS) tariff and NU’s local network service (LNS) tariff.  NU’s LNS tariff is also reset on June 1^st of each year to coincide with the change in RNS rates.  Additionally, NU’s LNS tariff provides for a true-up to actual costs which ensures that NU recovers its total transmission revenue requirements, including the allowed ROE.  Through December 31, 2004, this true-up has resulted in the recognition of a $4.6 million regulatory liability for refund to electric distribution companies, including CL&P, PSNH and WMECO.

On October 31, 2003, ISO-NE, along with NU and six other New England transmission owning companies (the New England TOs), filed a proposal with the FERC to create an RTO for New England in compliance with a 1999 FERC order calling on all transmission owners to voluntarily join RTOs (Order 2000).  In a separate filing made on November 4, 2003, the New England TOs requested, consistent with the FERC’s pricing policy for RTOs, that the FERC approve a single ROE for regional and local transmission service rates that would consist of a proposed 12.8 percent base ROE as well as incentive adders of 0.5 percent for joining an RTO and 1.0 percent for constructing new transmission facilities approved by the RTO.

On March 24, 2004, the FERC issued an order conditionally accepting the New England RTO proposal, but set for hearing the determination of the appropriate base ROE for transmission rates under the RTO and the clarification as to which facilities the 1.0 percent incentive adder should apply.  The 0.5 percent ROE adder was accepted for regional rates.  The March 24 order also required a number of compliance filings which were made in June, August and September of 2004.

On November 3, 2004, the FERC issued an order that (i) determined that the New England transmission owners' methodology used to calculate the proposed ROE is appropriate, (ii) clarified the application of the 0.5 percent incentive adder for joining a RTO and reaffirmed the appropriateness of the 1.0 percent incentive adder for new investments, however, left still unresolved the type of investments to which the 1.0 percent incentive adder should apply, and (iii) approved certain compliance items that were required by the FERC's March 24, 2004 order.

While the order approved the methodology that had been proposed by the transmission owners for calculating the base ROE, it determined that the actual base ROE would be determined following conclusion of the ordered hearing, which commenced on January 25, 2005.  As part of the hearing procedures, the New England TOs submitted supplemental testimony supporting their ROE proposal on January 10, 2005 that, among other things, updated the ROE calculations submitted with the November 2003 filing.  An initial administrative law judge decision on these issues is expected in May 2005, and a final FERC ruling regarding these issues is expected by the first quarter of 2006.

In January 2005, the boards of the New England TOs (including the operating company boards of CL&P, WMECO and PSNH) voted affirmatively to approve activation of the RTO, which occurred on February 1, 2005.  As of February 1, 2005, transmission rates will be adjusted to reflect the ROEs proposed by the New England TOs in the original RTO filing (12.8 plus requested 0.5 percent), subject to refunds to reflect the ROE resulting from the ultimate outcome of the hearings.  Management cannot at this time predict the ultimate ROE that will be determined following the hearings.

CL&P, PSNH and WMECO are also expected to experience locational installed capacity (LICAP) charges subsequent to their implementation by the FERC.  Because southwest Connecticut is a constrained area with insufficient generation, CL&P could see LICAP costs of several hundred million dollars.  These costs would be recovered from customers through the federally mandated congestion charge (FMCC) mechanism.  For further information on LICAP, see "Competitive System Businesses – Electric Generation."

Rates - General

CL&P, WMECO and PSNH have undergone fundamental changes in their business operations as a result of the restructuring of the electric industry in their respective jurisdictions.  CL&P and WMECO have divested all of their generation assets and are now acting as transmission and distribution companies.  PSNH has divested all ownership of nuclear generation.  Under New Hampshire law, PSNH may not divest its fossil/hydro generation assets until April 2006 at the earliest; thereafter, divestiture may occur only if the NHPUC determines that such divestiture is in the economic interest of retail customers of PSNH.

CL&P, PSNH and WMECO have received regulatory orders allowing each to recover all or substantially all of their prudently incurred stranded costs which are pre-restructuring expenditures incurred, or commitments made for future expenditures, on behalf of customers with the expectation such expenditures would continue to be recoverable in the future through rates.  All three companies have

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recovered significant portions of their stranded costs through the issuance of rate reduction bonds (RRBs) and rate reduction certificates (RRCs) (securitization) and are recovering the costs of securitization through rates.  As of December 31, 2004, CL&P had fully recovered all stranded costs except those being recovered through RRB-related charges, ongoing independent power producer costs, costs associated with the ongoing decommissioning of the Maine Yankee, Connecticut Yankee and Yankee Rowe nuclear units and annual decontamination and decommissioning costs payable under federal law.

All of NU’s electric operating company customers are now able to choose their energy suppliers, with the electric companies furnishing "standard offer," "default" or "transition" service to those customers who do not choose a competitive supplier.  Management recognizes that in other states electric companies have been negatively affected by the inability to recover supply costs on a timely basis.  To date, regulators have allowed the NU companies recovery of such costs in full, and management believes that current statutes and regulatory policy in Connecticut, Massachusetts and New Hampshire will continue to permit timely recovery.

In accordance with amendments passed in 2003 to Connecticut's electric restructuring legislation, CL&P signed fixed-price contracts in 2003 and 2004 with four wholesale suppliers who together will serve all of CL&P's transitional standard offer (TSO) requirements in 2005. None of CL&P’s suppliers for 2005 is affiliated with the company.  CL&P is fully recovering all of the payments it is making to those suppliers and has financial guarantees from each supplier to mitigate CL&P from risk in the event any of the suppliers encounters financial difficulties.  CL&P has filled a portion of its TSO requirements for 2006 and will initiate a new solicitation process in the future to procure generation supply for the unfilled portion of its TSO load obligation for that year.  See "Connecticut Retail Rates."

After a competitive solicitation, WMECO signed supply agreements for standard offer service in October 2003 for the period January 1, 2004 through February 28, 2005 (the transition period in which standard offer service is to be available terminated on February 28, 2005).  Select Energy was one of two winning bidders; the second was an unaffiliated supplier.  The DTE approved the standard offer contract and approved rates which will allow WMECO to recover fully its standard offer service supply costs.  In addition, in Massachusetts there is a second type of service supplied by electric distribution companies called default service.  Default service is provided to those customers not on competitive supply that are not eligible for standard offer service.  On March 1, 2005, these customers remaining on standard offer service were switched to default service.  Under current state law, default service, which the DTE has determined for purposes of customer communications is to be referred to as “basic service,” will continue indefinitely.

Pursuant to a DTE order issued in 2003, there are now two separate solicitations for default service.  For larger customers, WMECO default service rates are set for a three-month period.  For smaller customers, WMECO default service rates are set for a six-month period.  Accordingly, default service has been solicited and rates approved for larger customers for the period January 1, 2005 through March 31, 2005.  A single unaffiliated entity is the supplier.  Default service has been solicited and rates have been approved for smaller customers for the period January 1, 2005 through June 30, 2005.  Two unaffiliated entities will provide this service.  For larger customers, WMECO has awarded default service for the period April 1, 2005 through June 30, 2005 to Select Energy.  On December 6, 2004, the DTE opened an investigation seeking to determine if the manner in which default service is procured for smaller customers should be changed.  It is not known when the DTE will issue an order in this proceeding.  

PSNH provides transition energy service (TS) and default energy service (DS) to its retail customers from its generating plants, from power purchased under long-term contracts and from open market purchases.  PSNH reconciles its cost and rate recovery in periodic TS/DS rate proceedings.  See "New Hampshire Retail Rates."

Connecticut Retail Rates

CL&P – Rate Matters

Since retail competition began in Connecticut in 2000, most of CL&P's customers have continued to buy their power from CL&P at standard offer rates (2000-2003) and TSO rates (2004-2006).  Only a small number of CL&P customers (approximately 21,000 out of nearly 1.2 million) have opted for a competitive retail supplier.

Pursuant to state law, CL&P filed a rate case on August 1, 2003.  The DPUC issued a final decision in December, 2003, effective January 1, 2004, that authorized rate recovery of approximately $900 million over four years for its distribution capital program; approved incremental distribution rate increases totaling approximately $42.1 million between January 1, 2004 and December 31, 2007; applied $120 million of prior year generation service charge overcollections as credits against the authorized rate increases in the amount of $30 million per year; authorized a transmission rate increase of $28.4 million for 2004 with the understanding that CL&P could seek DPUC approval to reflect any future transmission-related revenue requirement increases in rates; and approved an ROE of 9.85 percent with earnings above that level to be shared 50/50 between customers and shareholders.  These rates are included in CL&P's total TSO rates.  On December 31, 2003, CL&P filed a petition for reconsideration (Petition) of the DPUC's final decision on the grounds that the final decision improperly (i) disallowed $15.7 million of CL&P's pension-related costs, (ii) concluded that the Connecticut statute of limitations does not apply to claims alleging that CL&P over-billed municipalities for streetlighting costs, and (iii) failed to implement additional

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revenue requirement adjustments equal to approximately $5.3 million, $3.6 million, $4 million and $4 million in 2004 through 2007, respectively.

Also, pursuant to state law, on December 19, 2003, the DPUC set CL&P’s TSO rates for January 1 through December 31, 2004 and confirmed that state law exempted FMCC charges, Energy Adjustment Clause (EAC) charges and certain other charges from the statutorily imposed rate cap.  The Connecticut Office of Consumer Counsel (OCC) has appealed this decision to the Connecticut Superior Court.  The OCC claims that the decision improperly implements an EAC charge under Connecticut law, fails to properly define and identify the fees that CL&P will be allowed to collect from customers, and improperly calculates base rates for purposes of determining the rate cap.

On August 4, 2004, the DPUC issued a decision on reconsideration allowing additional recovery for CL&P’s pension related regulatory asset, incentive compensation, rental expense and income taxes, in the total amount of approximately $24 million (net present value), and placing a limitation on the company’s liability for claims for streetlight account refunds.  Oral argument on the OCC’s appeal of this decision was held on March 11, 2005.  

On November 24, 2004, the DPUC issued a final decision that identified which specific costs imposed on CL&P by the FERC or ISO-NE constitute FMCCs within the meaning of Connecticut Public Act 03-135, as amended, and established a semi-annual proceeding to reconcile CL&P’s FMCC charges that are recovered through rates.  The DPUC’s decision also authorized CL&P to seek adjustments to its FMCC charges outside of a semi-annual reconciliation proceeding sooner in the event an adjustment is necessary to reflect changes necessitated by the procurement of additional power to serve CL&P’s TSO load or if there is a material change in FMCC expenses.  On February 1, 2005, CL&P filed for approval for a 1.6 percent increase to rates ($29.2 million) to collect additional FMCCs effective May 1, 2005.  The increase is necessary to collect costs related to an additional reliability must run (RMR) contract related to two generating plants located in southwest Connecticut.  The RMR contract has preliminary approval for billing from the FERC and is subject to a future review by the FERC for final approval.

On December 22, 2004, the DPUC issued a final decision setting CL&P’s TSO rates for January 1 through December 31, 2005.  The decision approved an increase of approximately 10.4 percent above the average rates in effect in January 2004.  The increase was necessary to collect higher costs for TSO generation supply and higher FMCCs.  One percentage point of the increase was necessary to implement the increase to CL&P’s distribution rate previously approved for 2005.  On February 3, 2005, the OCC filed an appeal with the Connecticut Superior Court challenging this decision.  This appeal is identical to the appeal filed with the same court in February 2004 challenging the DPUC’s December 2003 decision.

On August 4, 2004, the DPUC issued a decision concerning the reconciliation of two components of CL&P’s retail rates, the competitive transition assessment (CTA) and the systems benefits charge (SBC), for calendar year 2003.  The CTA recovers CL&P’s DPUC-approved stranded costs from customers.  The August 4 decision required CL&P to credit customers with the hypothetical profit CL&P would have realized from its purchase and sale of 250,000 megawatt hours (MWhs) of power from the Connecticut Resources Recovery Authority’s (CRRA’s) generating project in Hartford (the Market Price Cost Differential).  The energy purchase agreement under which CL&P was purchasing this power from CRRA’s Hartford generating project was rejected by a Bankruptcy Court in March 2003, and CL&P made no such purchases or sales in 2003.  The decision nevertheless directed CL&P to credit the $2.7 million Market Price Cost Differential for 2003 to customers.  In addition, the DPUC ordered CL&P to credit the Market Price Cost Differential for each year from 2004 through 2012 (the end date of the rejected power purchase agreement).  CL&P subsequently appealed the August 4 decision.  On December 1, 2004, based on a settlement CL&P reached with CRRA, the Connecticut Attorney General and DPUC’s Prosecutorial Staff, the DPUC issued a decision in the same proceeding that rescinded this portion of its August 4, 2004 decision.  

In the 2001 CTA and SBC reconciliation filing, and subsequently in a September 10, 2002 petition to reopen related proceedings, CL&P requested that a deferred intercompany tax liability associated with the intercompany sale of generation assets be excluded from the calculation of CTA revenue requirements.  On September 10, 2003, the DPUC issued a final decision denying CL&P’s request, and on October 24, 2003, CL&P appealed the DPUC’s final decision to the Connecticut Superior Court.  The appeal has been fully briefed and argued.  A decision from the court is not expected to be issued until the second quarter of 2005.  If CL&P’s request is granted through these court proceedings, then there could be additional amounts due to CL&P from its customers.  The 2004 impact of including the deferred intercompany liability in CTA revenue requirements has been a reduction of approximately $19.3 million in revenue.

In October 2002, CL&P filed a complaint at the FERC seeking interpretation of a FERC-filed interconnection agreement in which NRG agreed to pay CL&P's applicable retail rates for station service power (if procured from CL&P) and delivery of such power (whether procured from CL&P or a third party supplier).  By order dated December 20, 2002, the FERC affirmed the language in its Order 888 concerning state jurisdiction over the delivery of power to end users, even in the absence of distribution facilities, and the state's authority to impose certain charges on end users, such as those associated with stranded cost recovery.  CL&P subsequently made a demand upon NRG for payment of $13.3 million in station service charges through January 2003 and initiated a proceeding at the DPUC seeking a declaratory ruling that its DPUC approved rates were appropriately charged to NRG.  Prior to a DPUC ruling, NRG filed a petition for relief under Chapter 11 of the U.S. Bankruptcy Code.  On September 18, 2003, the Bankruptcy Court approved a stipulation

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between CL&P and NRG to submit the station service dispute to arbitration.  As part of the CL&P rate case decision dated December 17, 2003, the DPUC determined that CL&P had appropriately administered its station service rates.  Subsequently, however, in unrelated proceedings, the FERC issued a series of orders with conflicting policy direction which call into question its December 20, 2003 NRG order.  In July 2004, CL&P filed a request with the FERC for further clarification of this issue.  Arbitration proceedings have been initiated by the parties, but no hearing dates have been scheduled.  For further information relating to NRG-related litigation, see Item 3, "Legal Proceedings."  

On February 1, 2005, CL&P filed an application with the DPUC to obtain approval to defer for future recovery in its retail transmission rate the increased transmission costs that CL&P is incurring as of February 1, 2005.  If the DPUC does not approve the proposal to defer the increased transmission costs, CL&P’s filing makes an alternative proposal to increase its retail transmission rate to recover an additional $7.6 million on an annual basis, effective February 1, 2005.  As a result, CL&P’s approved annual transmission revenue requirement would be $121.2 million.  This increase would equal 0.031 cents per kWh, and would represent about a 0.2 percent increase in overall rates as of February 1, 2005, and an increase of about 6.7 percent to the transmission rate.

CL&P – Transmission Projects

CL&P has undertaken a substantial transmission construction program over the past several years.  On August 19, 2004, a Connecticut Superior Court judge dismissed an appeal by the City of Norwalk contesting the permit granted to CL&P by the CSC to construct a 21-mile, 345 kV transmission project from Bethel, Connecticut to Norwalk, Connecticut.  Based upon a recently completed estimate, the project is currently projected to cost between $300 million and $350 million.  The project is expected to begin to alleviate identified reliability issues in southwest Connecticut and to help offset rising federally mandated and other costs for all of Connecticut. Work on the related substations has begun, and work on the transmission lines is expected to start in March 2005 after finalization of construction contracts with vendors and receipt of permits from the affected towns and the Connecticut Department of Transportation. Management estimates a project completion date of December 2006.  At December 31, 2004, CL&P has capitalized $65 million associated with this project.

On October 9, 2003, CL&P and The United Illuminating Company (UI) filed for approval at the CSC for a separate 69-mile 345 kV transmission line from Middletown, Connecticut to Norwalk, Connecticut.  Construction is expected to commence after the final route and configuration are determined by CSC.  CL&P and UI initially estimated a cost of $620 million for the total project.  In June 2004, after ISO-NE raised concerns over the amount of underground line that had been proposed, the CSC requested that a committee comprised of representatives of CL&P, UI and ISO-NE study various alternatives and reach a consensus on the proposed project configuration.  The committee’s report was filed on December 20, 2004 and recommended a maximum of 24 miles of underground line.  On December 28, 2004 CL&P and UI filed updated cost estimates with the CSC which reflect changes needed to address technical issues introduced by the extensive amount of underground transmission being proposed and a two-year delay in the project in-service date from 2007 to 2009.  The new estimates place the cost of the project between $840 million and $990 million.  The variation in the cost range is due to unknown conditions that may be encountered during construction and a provision for other contingencies.  Additional steps to lower magnetic fields along the overhead portion of the route proposed by the CSC would add between $70 million and $80 million to the estimated cost.  The CSC concluded hearings on the proposal and the alternatives on February 17, 2005 and set a briefing schedule at that time.  A ruling on the proposed project is expected by April 7, 2005.  At December 31, 2004, CL&P has capitalized $18 million associated with this project. CL&P's share of this project is 80 percent and UI's share is 20 percent.  

In September 2002, the CSC approved a plan to replace an undersea 13-mile electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York.  This project is estimated to cost in the range of $114 to $135 million, and CL&P and the Long Island Power Authority (LIPA) will each own approximately 50 percent of the line.  CL&P has not yet signed a contract with a vendor to complete this work; therefore, the cost estimate could increase.  The project has received CSC approval but still requires federal and New York state approvals.  On October 1, 2004, consistent with a comprehensive settlement agreement reached on June 24, 2004, CL&P and LIPA jointly filed an implementation plan for the cable replacement with the Connecticut Department of Environmental Protection (CDEP).  Construction activities are scheduled to begin in the fall of 2006.  Management expects the cable to be in service by the middle of 2008.  At December 31, 2004, CL&P has capitalized $7 million related to this project.   

In May 2004, CL&P applied to the CSC to construct two nine-mile 115 kV underground transmission lines between Norwalk, Connecticut and Stamford, Connecticut.  The project is expected to cost approximately $120 million and will help meet the growing electric demands in the area.  Management expects the lines to be in service by 2008.  At December 31, 2004, CL&P has capitalized $3 million related to this project.  

During 2004, NU placed in service $123 million of electric transmission projects.  These projects included CL&P's $38 million upgrade of a transmission substation in Stamford, Connecticut that allows additional imports into southwest Connecticut.  

For further information on NU’s transmission construction program, see "Construction and Capital Improvement Program."

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Yankee Gas

In 2002, the DPUC approved an Infrastructure Expansion Rate Mechanism (IERM) to enable Yankee Gas to add some significant expansion projects to rate base in a limited proceeding, rather than requiring the filing of a full rate case.  On April 24, 2003, the Connecticut OCC appealed the DPUC’s decision, challenging the legality of the IERM.  Yankee Gas filed its 2003-2004 IERM application with the DPUC on October 1, 2003.  On April 27, 2004, Yankee Gas and the OCC reached a settlement concerning all of the pending IERM-related claims between the parties and eliminating the IERM as a rate making mechanism and providing for recovery of approximately $32 million in capital expenditures.  The settlement was approved by the DPUC on August 4, 2004.

On September 3, 2004, in connection with Yankee Gas’ filing to construct and operate a 1.2 billion cubic foot liquefied natural gas (LNG) facility, the DPUC concluded that there was a need for the LNG capacity and that construction of the facility was a reasonable approach to satisfying that need in light of the facility’s reliability and operational benefits.  In that decision, the DPUC also concluded that Yankee Gas’ actions incurred in pursuit of the proposed LNG facility had been prudent and authorized Yankee Gas to defer these costs for future recovery.  The DPUC also granted a rebuttable presumption of prudence for the facility’s contract construction costs, associated construction phase property taxes and AFUDC expenditures in a future rate case in which the facility will be placed into rate base.  Construction of the facility has begun and it is expected to be in service by the 2007-2008 heating season at an estimated cost of $108 million.

On December 8, 2004, the DPUC approved in full a rate case settlement between Yankee Gas, the OCC and the Prosecutorial Division of the DPUC.  The decision allowed a rate increase for Yankee Gas as of January 1, 2005 in the amount of $14 million (4.1 percent to total costs, 9.4 percent to distribution portion of rates), with an ROE of 9.9 percent.  Yankee Gas was also allowed lower depreciation expense related to costs of removal due to adequate reserve levels, which will lower Yankee Gas’ expenses by $5.7 million annually.  Under the settlement agreement, Yankee Gas agreed not to file a new application for a rate increase that would become effective prior to the earlier of (i) the in-service date of the LNG facility; or (ii) July 1, 2007.  However, Yankee Gas reserved the right to request rate relief that would become effective prior to July 1, 2007 if it incurs or will incur unanticipated substantial and material cost increases as a result of changes in law, administrative requirements or accounting standards, or due to a force majeure event.

Massachusetts Retail Rates

Massachusetts enacted comprehensive electric utility industry restructuring in November 1997.  That legislation required each electric company to submit a restructuring plan and to reduce its rates by 15 percent adjusted for inflation by September 1999. The 15 percent rate reduction is a rate cap for standard offer service customers that extends until February 28, 2005, the end of the restructuring transition period.

On December 29, 2004, the DTE approved a rate settlement entered into by WMECO, the Massachusetts Attorney General, the Associated Industries of Massachusetts and the Low-Income Energy Affordability Network.  The approved rate settlement allows WMECO to increase the distribution component of its rates to collect an additional $6.0 million in calendar 2005 and  an additional $3.0 million above 2005 distribution rates in calendar 2006.  Under the rate settlement, WMECO will also reduce its transition charge to approximately five mills, or $13 million, during calendar 2005 and 2006, although the charge will be no lower, in any case, than necessary to service WMECO's outstanding RRBs.

Other provisions of the rate settlement provide : (i) that WMECO will not seek any further distribution rate increase that would become effective before January 1, 2007 other than if its ROE drops below 7.0 percent; (ii) for an earnings sharing mechanism should WMECO’s ROE exceed 11 percent or drop below seven percent, providing a 50-50 sharing of excess earnings or future recovery of deficit earnings from customers and shareholders after DTE review; (iii) that WMECO will spend not less than $24 million in 2005 and 2006 on capital expenditures related to reliability; (iv) that WMECO will expand a program for low-income customers having difficulty in paying their bills, with the costs of such expansion in excess of the benefits to be recovered in WMECO's next general distribution rate case; and (v) that WMECO will send a reliability "report card" to its customers each year and work with the Massachusetts Attorney General on service quality issues.    

New Hampshire Retail Rates

On January 1, 2004, PSNH acquired the franchise and electric system of Connecticut Valley Electric Company, Inc. (CVEC), a subsidiary of Central Vermont Public Service Corporation (CVPS) that serves approximately 11,000 customers in western New Hampshire.  PSNH paid CVEC approximately $9 million for its assets and an additional $21 million for intangibles related to termination of a wholesale power contract between CVPS and CVEC.  Upon closing, customers of CVEC became customers of PSNH.  PSNH is recovering the $21 million payment with a return as a Part 3 stranded cost as defined in the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement).  Part 3 stranded costs are non-securitized regulatory assets which must be recovered by a recovery end date determined in accordance with the April 2000 Restructuring Settlement or be written off.

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Under the terms of the Restructuring Agreement, PSNH provides both DS and TS to its customers, and DS/TS are priced at the same rate.  On February 1, 2005, PSNH adjusted the costs it charges for generation services for the period February 1, 2005 through January 31, 2006.  PSNH increased the DS/TS rates to 6.49 cents per kWh from 5.79 cents per kWh for all retail customers.  The increase in the DS/TS rates allows PSNH to recover all actual and prudent costs, including the 11 percent ROE PSNH has previously been allowed on its net generation assets.  In its January 28, 2005 order approving the February 2005 DS/TS rates, the NHPUC allowed the 11 percent ROE on an interim basis but deferred a decision on whether it was appropriate to continue to allow PSNH an 11 percent ROE in calculating DS/TS costs.  The NHPUC has ordered a supplemental phase of this proceeding that will lead to a NHPUC decision on PSNH’s appropriate ROE on generation investments by June 1, 2005.  The NHPUC’s January 2005 rate order allows for a midyear correction in the DS/TS rate.  While management is unable to predict the outcome of the ROE docket, it expects that any material changes in the generation ROE would be implemented prospectively as part of the midyear correction in DS/TS rates that would be effective August 1, 2005.

PSNH's delivery rates were fixed by the Restructuring Settlement until February 1, 2004.  Pursuant to the Restructuring Settlement and New Hampshire statute, PSNH filed a delivery service rate case on December 29, 2003.  On September 2, 2004, the NHPUC approved a settlement providing for a $3.5 million increase in delivery service revenues on October 1, 2004 and an additional increase of $10 million on June 1, 2005, for a total rate increase of $13.5 million.

In August 2003, PSNH sought the approval of the NHPUC to modify one of its older 50 MW coal-fired generating stations, Unit 5 at Schiller Station in Portsmouth (Northern Wood Power Project), to a technologically advanced fluidized bed boiler capable of burning wood, with the plan to burn locally sourced low-grade wood fuel.  This project would qualify Schiller Unit 5 to receive revenues from the sale of renewable energy certificates necessary to fulfill renewable portfolio standard requirements in Connecticut and Massachusetts.   In May 2004, the NHPUC approved the Northern Wood Power Project and a risk/reward cost-recovery mechanism jointly offered by PSNH, the New Hampshire Governor’s Office of Energy and Planning, the New Hampshire Office of Consumer Advocate, and the New Hampshire Timberland Owners’ Association.  Construction of the facility has commenced.  For information on the appeal of the NHPUC’s orders pending with the New Hampshire Supreme Court, see Item 3, "Legal Proceedings."

COMPETITIVE SYSTEM BUSINESSES

NU is engaged in a variety of competitive businesses, primarily the retail and wholesale marketing of electricity and natural gas in the northeastern United States and the provision of energy related services to large government, industrial, commercial and institutional facilities.

NUEI is a wholly-owned subsidiary of NU and acts as the holding company for certain of NU's competitive energy subsidiaries.  These subsidiaries include SESI, a provider of energy management, demand-side management and related consulting services for commercial, industrial and institutional customers and electric utility companies; NGC, a corporation that acquires and manages generation facilities; NGS, a corporation that maintains and services fossil and hydroelectric facilities and provides high-voltage electrical contracting services, and Select Energy, a corporation engaged in the marketing, transportation, storage and sale of energy commodities, at wholesale and retail, in designated geographical areas. The generation operations of HWP are also included in the results of NUEI.  NUEI and its integrated competitive energy business affiliates had aggregate revenues of approximately $2.9 billion in 2004 as compared to approximately $2.6 billion in 2003 and had losses of $15.1 million in 2004, as compared to a loss of approximately $3.4 million in 2003.

NGC is the competitive generating subsidiary of NU and a major provider of pumped storage and conventional hydroelectric power in the northeastern United States.  NGC sells all its generation output to Select Energy, which in turn markets it to customers.  Select Energy also buys and manages the entire generation output of HWP, which consists of approximately 147 megawatts (MW) of coal-fired generation at the Mt. Tom station in Holyoke, Massachusetts under an evergreen contract.  NGC's assets and Mt. Tom perform functions that are critical to NUEI's wholesale and retail businesses by providing Select Energy with access to electric generation within New England and thus reducing its exposure to energy price fluctuations.

On March 9, 2005, NU announced that it had completed its previously announced comprehensive review of its competitive energy businesses and that it has decided that NUEI will exit the wholesale marketing business, which it conducts through its subsidiary Select Energy, and will explore ways to divest its competitive energy services businesses.  NU concluded that the wholesale merchant energy sector in the power pools between Maine and Maryland is becoming increasingly competitive and that NUEI’s wholesale marketing business will be unable to attain the profit margins necessary to generate acceptable returns and cash flows.  As a result, NUEI will explore a number of alternatives for exiting the wholesale marketing business, including selling the wholesale marketing franchise, selling existing contracts, restructuring longer term contracts, and allowing shorter term contracts to expire without being renewed.  Select Energy will only bid on new full requirements wholesale contracts to improve the value of its book of business by reducing existing electric positions.  NU will retain its 1,443 megawatts of competitive generating assets because it expects that their value could increase significantly in the coming years.  It will also retain NGS, which principally operates these plants.

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Retail and Wholesale Marketing

NUEI, through Select Energy, sells multiple energy products including electricity and natural gas to wholesale and retail customers in the northeastern United States.  Select Energy procures and delivers energy and capacity required to serve its electric and gas customers.  In order to support and complement its growing wholesale and retail business, Select Energy contracted in December of 1999 with NGC to purchase and market all of NGC's 1,296 MW for a six-year period, extended through December 2007.  In addition, during 2004 Select Energy purchased approximately 147 MW of coal generating plant output from its affiliate, HWP, and more than 4,000 MW of electrical supply from various New England generating facilities on a long-term basis to meet its New England load obligations.  Select Energy utilizes generation failure insurance, options and energy futures to hedge its supply requirements.  NUEI also offers energy management consulting and construction services through its affiliate, SESI, discussed more fully below.

In 2004, Select Energy reported revenues of $2.6 billion and had retail and wholesale marketing sales of approximately 41,000 gigawatt-hours (GWh) of electricity and 57 billion cubic feet (BcF) of natural gas to approximately 30,000 customers.  During 2003, Select Energy reported revenues of $2.3 billion and had retail and wholesale marketing sales of approximately 40,000 GWh of electricity and 46 BcF of natural gas to approximately 26,000 customers.

In general, over the last few years, the market for energy products has become shorter term in nature with less liquidity and participants are sometimes unable to meet Select Energy's credit standards without providing cash or LOC support.  In addition, wholesale power competition increased significantly in New England over the last six months of 2004.  Select Energy’s business has been adversely affected by these factors and they contributed to NU’s decision to exit the wholesale competitive energy business.

Changes are occurring in the administration of transmission systems in territories in which Select Energy does business.  RTOs are being proposed and approved and other changes in market design are occurring within transmission regions.  The impact of SMD on the wholesale marketing business has been significant.  As the market continues to evolve, there could be additional challenges or opportunities that management cannot determine at this time.  For more information on the proposed changes, see "Regulated Electric Operations- Transmission Access and FERC Regulatory Charges" and "Regulated Electric Operations-Connecticut Retail Rates."

Retail Marketing

Select Energy is licensed to provide retail electric supply in Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, Ohio, Pennsylvania, Virginia, the District of Columbia, New York and Rhode Island.  Within these states, Select Energy is currently registered with 38 electric distribution companies and 54 gas distribution companies to provide retail services.

Select Energy's retail marketing business had a $6.7 million improvement in performance during 2004, with net income of $4.9 million versus a loss of $1.8 million in 2003.  The stronger performance is attributed to increased electric and gas sales, which increased from approximately $660 million in 2003 to approximately $850 million in 2004.  Select Energy expects its retail marketing business to repeat its success and to be similarly profitable in 2005, when it projects approximately $1 billion in sales.  This projection assumes that Select Energy will be successful in securing and managing a significant amount of new business at acceptable margins.

As of December 31, 2004, Select Energy had contracts with retail electric customers in states throughout the Northeast which produced revenues of approximately $560 million, from over 1,800 MW of peak load at approximately 18,000 locations, including predominately commercial, industrial, institutional and governmental accounts.  As over 700 MW of this load is in New England, Select Energy is among the largest competitive retail suppliers of electricity in New England as measured by MW load.  During 2004, retail load totaled nearly 10 million MWh.  No single retail electric customer accounted for more than ten percent of Select Energy's retail revenues.

During 2004, Select Energy's competitive natural gas business, which is primarily retail in nature, produced revenues of approximately $410 million, an increase from 2003 revenues of approximately $129 million.  This increase relates to both higher gas prices and higher gas volumes.  As of December 31, 2004, Select Energy provided over 39 BcF of natural gas to approximately 12,000 retail gas customers, primarily located in Connecticut, Massachusetts, New York and Pennsylvania.  These contracts generally have one-year terms and include primarily commercial, institutional, industrial and governmental accounts.  No single retail gas customer accounted for more than ten percent of Select Energy's retail gas revenues.  

Wholesale Marketing

In 2004, Select Energy supplied more than 5,800 MW of standard offer and default service load in the Northeast, making it one of the largest providers of standard offer service in that region.  Revenues from these services comprised in the aggregate approximately 54 percent of Select Energy's 2004 revenues.

During 2004, the wholesale marketing business lost $17 million, primarily due to a $48.3 million mark-to-market loss associated with certain wholesale natural gas positions established to economically hedge electricity purchased in anticipation of winning certain

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levels of wholesale electric load in New England.  In 2003, that business lost $3.7 million due to a $35.6 million write-off relating to a contract settlement between Select Energy and CL&P.

In 2004, Select Energy served approximately 1,800 MW of TSO load of its affiliate, CL&P.  Total Select Energy revenues from serving CL&P’s standard offer load, TSO load and for other transactions with CL&P represented $611.3 million or 21 percent of NUEI's total revenues for the year ended December 31, 2004.  In addition to its contract with CL&P, Select Energy revenues related to contracts with NSTAR companies represented $300.2 million or 11 percent of NUEI’s total revenues for the year ended December 31, 2004.  Select Energy also provides basic generation service in the New Jersey and Maryland market.  Select Energy revenues related to these contracts represented $334.2 million or 12 percent of NUEI’s total revenues for the year ended December 31, 2004.  No other individual customer represented in excess of 10 percent of NUEI’s revenues for the year ended December 31, 2004.

On November 15, 2004, NU announced that Select Energy had been unsuccessful in its bid to supply a portion of the load for CL&P in 2005 and beyond.  As a result of the failure to secure any of the CL&P load and due to diminished levels of success in other New England bids, a comprehensive review of NUEI’s businesses, including that of Select Energy, was undertaken, which concluded on March 9, 2005 that Select Energy should exit the wholesale marketing business  See "Risk Factors" and "Competitive System Businesses."

Trading activities are limited primarily to price discovery, risk management and deal execution for merchant energy activities.

Electric Generation

NGC, NU's competitive electric generating affiliate, owns and operates a portfolio of approximately 1,296 MW of hydroelectric and pumped storage generating assets in Connecticut and Massachusetts.  NGC's portfolio consists of seven hydro facilities along the Housatonic River System, the three facilities comprising the Eastern Connecticut System, including one gas turbine, all located in Connecticut, and the Northfield Mountain pumped storage station and the Cabot and Turners Falls No. 1 hydroelectric stations located in Massachusetts.  NGC sells all of its energy and capacity to its affiliate, Select Energy.  Select Energy's performance under its contract with NGC is guaranteed by NU through 2007.  Select Energy also buys and manages the entire generation output of approximately 147 MW from HWP's Mt. Tom coal-fired generating plant under a contract renewable on an annual basis.  Select Energy uses the NGC and Mt. Tom generation to furnish a portion of the resources it uses to meet supply commitments to its marketing customers.  For further information relating to NU’s electric generating plants, see Item 2, "Properties – Electric Generating Plants."

NGC's contract with Select Energy extends through December 2007.  During the remaining term, 82 percent of NGC's revenues from this contract (including all of the revenues from Northfield Mountain) are in the form of predetermined, fixed monthly payments based on the capacity of specified facilities.  The remaining 18 percent of the revenues are in the form of monthly payments at predetermined rates per unit of actual energy output.  NGC expects to derive approximately 77 percent of its revenues from Northfield Mountain.  This contract provides NGC with a stable stream of revenues at prices that are currently higher than average wholesale electricity prices in the markets served by NGC's facilities.  

In March 2004, ISO-NE filed a proposal at the FERC to implement LICAP requirements.  LICAP is an administratively determined electric generation capacity pricing mechanism intended to provide a revenue stream sufficient to maintain existing generation assets, and encourage the construction of new generation assets at levels sufficient to serve peak load, plus a reserve margin and a cushion. In June 2004, the FERC ordered the creation of five LICAP zones and accepted ISO-NE’s demand curve methodology. The FERC ordered LICAP to be implemented by January 1, 2006 and set certain issues pertaining to the demand curve for hearings.  Hearings began in the end of February 2005.  In August 2004, ISO-NE revised its proposal and several intervenors, including FERC staff and various state regulators, have put forth alternative demand curve proposals.

Depending on the pricing curves that are ultimately implemented, LICAP could produce significant benefits for generation assets either owned or leased by NU’s competitive energy businesses.  Those benefits would likely be greater per kWh rates for generation located in Connecticut than generation assets located in Massachusetts because the capacity margin is much lower in Connecticut than it is in central and western Massachusetts.  As a result, LICAP values are likely to be higher in Connecticut.  NU’s competitive energy businesses own or lease approximately 300 megawatts in Connecticut and approximately 1,300 megawatts in western Massachusetts.  A FERC decision is anticipated in the fall of 2005.

 NU concluded a comprehensive review of its competitive energy businesses on March 9, 2005, and announced that it will retain its competitive generation.  See "Risk Factors" and "Competitive System Businesses."

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Competitive Energy Subsidiaries’ Market And Other Risks

The decision to exit the wholesale marketing business and limit wholesale marketing activities will change the risk profile of NUEI in 2005.  Subsequent to the disposition of the wholesale marketing business, NUEI will continue to be exposed to certain market risks; however, management believes that those risks will be reduced.  The merchant energy business segment will be comprised of generation assets and the retail marketing segment, which will enter into contracts of varying lengths of time to buy and sell energy commodities, including electricity, natural gas, and oil to retail customers.  Market risk represents the loss that may affect the merchant energy business segment’s financial results, primarily Select Energy, due to adverse changes in commodity market prices.

Risk management within Select Energy has been organized to address the market, credit and operational exposures arising from its wholesale marketing business (which includes limited energy trading for market and price discovery purposes) and its retail marketing activities.  A significant portion of the retail and wholesale marketing business is providing full requirements service to customers, primarily regulated distribution companies for the wholesale business and commercial, industrial, institutional and governmental accounts for the retail business.  The "full requirements" obligation commits these companies to supply the total energy requirement for the customers' load at all times.  An important component of Select Energy’s risk management strategy is to manage the volume and price risks of its full requirements contracts.  These risks include unexpected fluctuations in both supply and demand due to numerous factors which are not within its control, such as weather, plant availability, exposure to transmission congestion costs and price volatility.

In June 2004, Select Energy began purchasing fixed-price electricity and some electricity with prices indexed to gas for 2005 and 2006 in anticipation of winning full requirements contract sales and sales to load-serving entities.  Purchasing electricity in advance creates the risk of electricity price decreases before the full requirement quantities are contracted and before contract prices are known.  

To mitigate the risk of electricity price decreases on the fixed-price electricity that was purchased, Select Energy in June 2004 began selling wholesale natural gas contracts for 2005 and 2006.  The intended result of this risk mitigation strategy was that the value of the fixed-price electricity purchase contracts would be offset in part by increases in the value of the gas contracts, and vice versa.  Select Energy intended to purchase natural gas when quantities and prices of electricity are secured by full requirements contracts or sales contracts with load-serving entities.  Natural gas was sold in this risk mitigation strategy due to the high liquidity of the natural gas market compared to the low liquidity of electricity in the Northeast.  Select Energy’s failure to win large wholesale loads at competitive bidding in the fall of 2004 at previously experienced levels, combined with adverse price movements in both gas and electric markets, contributed significantly to wholesale marketing losses in 2004.

In serving its marketing customers, Select Energy utilizes derivative financial and commodity instruments, including options and forward contracts, to manage the risk of fluctuating market prices.  At December 31, 2004, Select Energy had hedging derivative assets of $4.5 million, as compared to hedging derivative assets of $56 million at December 31, 2003.  Generally, such derivatives impact earnings over the life of the contracts which they hedge, but in certain cases the impact is accelerated and affects earnings immediately.

Select Energy's trading portfolio had a net positive $29.6 million fair value at December 31, 2004, as compared to a net positive $32.5 million fair value at December 31, 2003.  Approximately 98 percent of the $29.6 million was priced from external sources and only a nominal amount was based on exchange quotes.  Of the $29.6 million of net fair value in the trading portfolio at December 31, 2004, $3.5 million will mature in 2005, $13.6 million in 2006-2008 and $12.5 million after 2008.

Accordingly, there is a risk that the trading portfolio will not be realized in the amount recorded.  Realization of cash will depend upon a number of factors over which Select Energy has limited or no control, including the accuracy of its valuation methodologies, the volatility of commodity prices, changes in market design and settlement mechanisms, the outcome of future transactions, the performance of counterparties, the breadth and depth of the trading market and other factors.

In addition, the application of derivative accounting principles is complex and requires management judgment in identification of derivatives and embedded derivatives, election and designation of the "normal purchases and sales" exceptions identifying hedge relationships and assessing hedge effectiveness, determining the fair value of derivatives and measuring hedge ineffectiveness.  All of these judgments, depending upon their timing and effect, can have a significant impact on the competitive subsidiaries' performance and, ultimately, NU's consolidated net income.

Risk management within the competitive energy subsidiaries, including Select Energy, is organized to address the market, credit and operational exposures arising from the merchant energy business segment, which include wholesale marketing activities (including limited energy trading for market and price discovery purposes), as well as asset optimization and retail marketing activities.  The framework for managing these risks is set forth in NU's risk management policies and procedures, which are reviewed by NU’s Board of Trustees on an as-needed basis.  

As a means to monitor and control compliance with these policies and procedures, NU has a Risk Oversight Committee (ROC) to monitor competitive energy risk management processes independently from the businesses that create and manage these risks.  The ROC

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ensures that the policies pertaining to these risks are followed and periodically adjusts the metrics used in measuring and controlling portfolio risk while also reviewing the methodologies employed by management to discern portfolio values.

Energy Management Services

NUEI has two affiliated companies in the energy related services business: NGS and SESI, which accounted for approximately $275 million of non–affiliate revenue in 2004.

NGS manages, operates, maintains and supports electric power generating equipment, facilities and associated transmission and distribution equipment and provides turnkey management and operation services to owners of electric generation facilities.  NGC and HWP have contracted with NGS to operate and maintain all of their generating plants.

Through its wholly-owned subsidiaries, E.S. Boulos Company (Boulos) and Woods Electrical Co., Inc. (Woods Electrical), NGS provides electrical construction and contracting services.  These services focus on high and medium voltage installations and upgrades and substation and switchyard construction.  Woods Network, a subsidiary of NUEI, is a network products and services company.

During 2004, NGS's revenues were approximately $113 million.   Forty-three percent of NGS's revenues in 2004 were derived from contracts with its affiliates, most of which related to NGS’s operation of NUEI’s competitive generation assets.  

SESI was acquired in 1990 and provides energy efficiency, design and construction solutions to government, institutional and commercial facilities.  In delivering its services, SESI focuses on reducing its customers' energy costs, improving the efficiency and reliability of their energy-consuming equipment and conserving energy and other resources.  SESI also designs, builds and maintains central energy plants producing power, heating and cooling for their hosts.  SESI's engineering and construction management services have been directed primarily to markets in the eastern United States.  SESI's subsidiary, Select Energy Contracting, Inc. (SECI), provides service contracts and mechanical and electrical contracting, primarily directed to energy systems in commercial markets.  In 2004, SESI had revenues of approximately $192 million.  In 2005, SESI's revenues are anticipated to decrease by 17 percent based on a new business model that focuses on more profitable projects rather than growth in revenue.

As a result of the comprehensive review of its competitive energy businesses, NU announced on March 9, 2005 that it will explore ways to divest its energy services businesses in a manner that maximizes their value, but intends to retain NGS and its competitive generation assets.  See "Risk Factors" and "Competitive System Businesses."

Telecommunications

Mode 1 is a wholly-owned exempt telecommunications subsidiary of NUEI.  Mode 1 is a licensed competitive local exchange carrier authorized to provide local phone service within the state of Connecticut.

At December 31, 2004, NU's net investment in Mode 1 was approximately $13 million, most of which was used to fund Mode 1's investment in NEON Communications, Inc. (NEON).  NEON is a wholesale provider of high bandwidth, advanced optical networking solutions and services to communications carriers on intercity, regional and metro networks in the twelve-state Northeast and mid-Atlantic markets, utilizing a portion of the NU system companies' and other electric utilities' transmission and distribution facilities.  During 2004, Mode 1 owned approximately 9.3 percent of NEON on a fully diluted basis.  NEON merged with Globix Communications, Inc., a website hosting company, on March 8, 2005.  Mode 1’s share in the combined companies is approximately 5.3 percent.

REGULATED GAS OPERATIONS

Yankee is the holding company of Yankee Gas and its two active non-utility subsidiaries, NorConn, which holds certain minor properties and facilities of Yankee and its subsidiaries, and Yankee Energy Financial Services Company, which provides Yankee Gas customers with financing for energy equipment installations.

Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers and size of service territory.  Total throughput (sales and transportation) for 2004 was 47.3 billion cubic feet.  In 2004, total gas operating revenues of $408 million were comprised of the following: 49 percent residential; 28 percent commercial; 20 percent industrial; and the remaining 3 percent other.  Yankee Gas provides firm gas sales service to customers who require a continuous gas supply throughout the year, such as residential customers who rely on gas for their heating, hot water and cooking needs.  Yankee Gas also provides interruptible gas sales service to certain commercial and industrial customers that have the capability to switch from natural gas to an alternative fuel on short notice.  Yankee Gas can interrupt service to these customers during peak demand periods.  Yankee Gas offers firm and interruptible transportation services to customers who purchase gas from sources other than Yankee Gas.  In addition, Yankee Gas performs gas sales, gas exchanges and capacity releases to marketers to reduce its overall gas expense.

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Although Yankee Gas is not subject to the FERC's jurisdiction, the FERC does have limited oversight over certain intrastate gas transportation that Yankee Gas provides.  In addition, it regulates the interstate pipelines serving Yankee Gas' service territory. Yankee Gas, therefore, is directly and substantially affected by the FERC's policies and actions.  Accordingly, Yankee Gas closely follows and, when appropriate, participates in proceedings before the FERC.

Yankee Gas is subject to regulation by the DPUC, which, among other things, has jurisdiction over rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities.  For information relating to Yankee Gas DPUC proceedings, see "Regulated Electric Operations - Connecticut Retail Rates."

For information on the proposed expansion of Yankee Gas' natural gas delivery system in Connecticut, see "Construction and Capital Improvement Program."

FINANCING PROGRAM

2004 Financings

On January 30, 2004, Yankee Gas issued $75 million of first mortgage bonds (the Series G Bonds) with a coupon of 4.80 percent and a maturity of January 1, 2014.  The proceeds of the transaction were used to refinance an increase in Yankee Gas’ short-term debt to fund its capital needs.

On July 7, 2004, CL&P entered into multiple agreements to renew and extend its $100 million accounts receivable sale program.  As part of the agreement, the bank commitment was extended for an additional 364 days through July 6, 2005, and the termination date of the facility was extended to July 3, 2007.

On July 22, 2004, PSNH issued $50 million of first mortgage bonds (the Series L Bonds) with a fixed coupon rate of 5.25 percent and a maturity of July 15, 2014.  The proceeds of this issuance were used to refinance short-term debt and to fund PSNH’s capital needs.

On September 17, 2004, CL&P issued $150 million of first mortgage bonds (the Series A Bonds) with a fixed coupon of 4.80 percent and a maturity of September 15, 2014.  CL&P also issued $130 million of first mortgage bonds (the Series B Bonds) with a fixed coupon of 5.75 percent and a maturity of September 15, 2034.  The proceeds of both issuances were used to refinance a portion of the company’s short-term debt, as well as the redemption of the company’s $59 million 1994 Series C bonds.  

On September 23, 2004, WMECO issued $50 million in senior unsecured notes (the Series B Notes) with a coupon of 5.90 percent and a maturity of September 15, 2034.  WMECO used the proceeds of the issuance to fund a trust established to match WMECO’s obligations to Dominion Resources, Inc. for its liability to the U.S. Department of Energy for pre-1983 Millstone spent nuclear fuel.

On November 8, 2004, CL&P, WMECO, PSNH and Yankee Gas entered into a new unsecured five-year revolving credit facility for $400 million, replacing a 364-day $300 million facility that expired on November 8, 2004, under which they will be able to borrow on a short-term basis and, subject to certain conditions, on a long-term basis.  CL&P may draw up to $200 million, and WMECO, PSNH and Yankee Gas may draw up to $100 million each, subject to the $400 million maximum for the entire facility.  Unless extended, the facility will expire on November 6, 2009.

On November 8, 2004, NU entered into a new unsecured five-year revolving credit facility for $500 million, replacing a 364-day $350 million facility that expired on November 8, 2004, under which it will be able to borrow on a short-term basis and, subject to certain conditions, on a long-term basis.  The new facility provides a total commitment of $500 million with a $350 million sub-limit for letters of credit.  Unless extended, the credit facility will expire on November 6, 2009.

On November 15, 2004, Yankee Gas issued $50 million of first mortgage bonds (the Series H Bonds) with a fixed coupon of 5.26 percent and a maturity of November 1, 2019.  The proceeds of this issuance were used primarily to pay back short-term debt incurred to redeem the company’s Series A, Tranche E and Series C first mortgage bonds.  

SESI engaged in various forms of off-balance sheet financing in 2004 associated with its demand side management business.

NU paid common dividends totaling $80.2 million in 2004, compared to $73.1 million paid in 2003, reflecting increases in the quarterly dividend rate that were effective September 30, 2003 and September 30, 2004.

Total NU system debt, including short-term debt, capitalized lease obligations and prior spent nuclear fuel liabilities, but not including RRCs and RRBs, was $3.1 billion as of December 31, 2004, compared with $2.7 billion as of December 31, 2003. The increase was primarily due to new debt issuances by CL&P, PSNH, WMECO and Yankee Gas.

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For more information regarding NU system financing, see "Notes to Consolidated Financial Statements" in NU's financial statements, the footnotes related to long-term debt, short-term debt, leases and the sale of accounts receivables, as applicable, in the notes to NU's, CL&P's, PSNH's, and WMECO's financial statements and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."  

2005 Financing Requirements

The NU system's aggregate capital requirements for 2005 are approximately as follows:

* CL&P, WMECO and PSNH have sinking funds associated with RRCs and RRBs that are not included in the capital requirements subtotal.  All interest and principal payments for these bonds are collected through a non-bypassable charge assessed to customers and do not represent additional capital requirements.

For further information on the NU system's 2005 financing requirements, see "Notes to Consolidated Financial Statements " in NU's financial statements, "Long-Term Debt" in the notes to CL&P's, PSNH's and WMECO's financial statements and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

2005 Financing Plans

CL&P plans to issue up to $200 million of debt, primarily to finance its distribution and transmission businesses and for general corporate purposes.  See –“Construction and Capital Improvement Program."

PSNH plans to issue up to $50 million of debt to refinance short-term debt and for general corporate purposes.

WMECO plans to issue up to $50 million of debt to refinance portions of its existing short-term debt and for general corporate purposes.

Yankee Gas plans to issue up to $50 million of debt to refinance maturing long-term debt, to finance its capital expenditures, including for the construction of its LNG facility, and for general corporate purposes.  See "Construction and Capital Improvement Program."

Financing Limitations  

Many of the NU system companies' charters and borrowing facilities contain financial limitations that must be satisfied before borrowings can be made and for outstanding borrowings to remain outstanding.  In addition, the NU system companies are subject to certain federal and state orders and policies which limit their financial activities.

Financial Covenants in Short-Term Debt Credit Facility

Under their current revolving credit facility agreement, CL&P, WMECO, PSNH and Yankee Gas are allowed to maintain a ratio of debt to total capitalization (leverage ratio) of no more than 65 percent.  At December 31, 2004, CL&P's, WMECO's, PSNH's, and Yankee Gas' leverage ratios were 51 percent, 55 percent, 55 percent and 37 percent, respectively.  This agreement also requires CL&P, WMECO and PSNH to maintain 12-month earnings before interest and taxes to interest expense ratio (interest coverage ratio) of at least 2.00 to 1.00 and requires Yankee Gas to maintain an interest coverage ratio of at least 1.75 to 1.00.  At December 31, 2004, CL&P's, WMECO's, PSNH's and Yankee Gas' interest coverage ratios were 3.88 to 1, 3.63 to 1, 4.20 to 1 and 2.03 to 1, respectively.  These ratios do not include RRBs and RRCs and the leverage ratio for Yankee Gas does not exclude goodwill from capitalization.

NU is allowed, under its current revolving short-term credit agreement facility, to maintain a debt to total capitalization (leverage ratio) of no more than 65 percent.  At December 31, 2004, NU's leverage ratio was 57 percent.  In addition, NU is required to maintain a 12-month consolidated interest coverage ratio of at least 2.00 to 1.00.  At December 31, 2004, NU's consolidated interest coverage ratio was 2.12 to 1.00.  These ratios do not include RRBs and RRCs.

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Short-Term Debt Limits

The amount of short-term debt that may be incurred by NU, CL&P, WMECO, Yankee, Yankee Gas and HWP is subject to periodic approval by the SEC under the Public Utility Holding Company Act of 1935 (1935 Act).  On June 30, 2004, the SEC issued an order extending these companies’ short-term debt authority and authority to participate in the Northeast Utilities System Money Pool (Money Pool) through June 30, 2007.  The order also authorized the participation of the competitive subsidiaries in the Money Pool through June 30, 2007, but did not limit their borrowings from the Money Pool.  NU, Yankee, Woods Network, NGC and Mode 1 may lend to, but are not authorized to borrow from, the Money Pool.  The following table shows the amount of short-term borrowings authorized for each company, as the case may be, as of December 31, 2004, and the amounts of outstanding short-term debt of those companies at the end of 2004 and as of March 1, 2005 (in millions):

(1)

These columns include borrowings of various NU system companies from NU, other NU system companies and unaffiliated lenders.  Total NU system short-term indebtedness to unaffiliated lenders was $180 million at December 31, 2004 and $301 million at March 1, 2005.

(2)

Under applicable NHPUC regulations, PSNH can incur short-term debt up to ten percent of fixed net plant or such other amount as approved by the NHPUC.  Pursuant to an order issued by the NHPUC, PSNH can incur short-term debt up to $100 million.  In the absence of an NHPUC order, PSNH’s short-term debt limits are subject to periodic approval by the SEC under the 1935 Act.

(3)

Pursuant to a DTE order, WMECO can lend through the Money Pool only to CL&P, HWP, NNECO, Quinnehtuk and Rocky River Realty, Inc. (RRR).

(4)

Includes RRR, Quinnehtuk, Yankee Financial, YESCO, NorConn Properties, Inc., NUEI, NGS, Boulos, Woods Electrical, Select Energy, NAEC, Northeast Nuclear Energy Company (NNECO), Select Energy New York, Inc., SESI and Properties, Inc.

Debt Issuance Limitations

CL&P's charter contains preferred stock provisions restricting the amount of additional unsecured debt it may incur.  At shareholders' meetings in November 2003, CL&P obtained authorization from its preferred stockholders to issue unsecured indebtedness with a maturity of less than ten years in excess of ten percent of capitalization (but not in excess of 20 percent of capitalization) for a ten-year period expiring March 2014.  As of December 31, 2004, the amount of additional unsecured debt it could incur was $394.8 million.

CL&P’s first mortgage bond indenture provides that additional bonds may not be issued based on bondable property additions, except for certain refunding purposes, unless: (i) net earnings during a period of twelve consecutive calendar months during the period of fifteen consecutive calendar months immediately preceding the first day of the month in which the application for additional bonds is made are at least twice the pro forma annual interest charges on outstanding bonds, certain prior lien obligations and bonds to be issued, and (ii) CL&P has available property credits equal to 166 2/3 percent of the principal amount of bonds to be issued. The indenture also allows CL&P to issue first mortgage bonds equal to the available amount of bonds previously issued but retired.  At December 31, 2004, CL&P could not issue any bonds based on bondable property additions, but could issue up to approximately $405.4 million based on available retired bond credits.   

Yankee Gas’ first mortgage bond indenture also provides that additional bonds may not be issued based on bondable property additions, except for certain refunding purposes, unless: (i) net earnings during a period of twelve consecutive calendar months during the period of fifteen consecutive calendar months immediately preceding the first day of the month in which the application for additional bonds is made are at least twice the pro forma annual interest charges on outstanding bonds, certain prior lien obligations and bonds to be issued and (ii) Yankee Gas has available property credits equal to 166 2/3 percent of the principal amount of bonds to be issued.  The

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indenture also allows Yankee Gas to issue first mortgage bonds equal to the available amount of bonds previously issued but retired, but subject under certain conditions to meeting the net earnings for interest test just described.  Yankee Gas would need to meet this test to issue first mortgage bonds based on any of its currently available prior redeemed bonds.  As of December 31, 2004, Yankee Gas' net earnings were 2.26 times the annual interest charges on its outstanding bonds.  Yankee Gas anticipates passing this interest coverage test after accounting for its planned issuance of $50 million in 2005 and issuing this debt under its first mortgage bond indenture.  If Yankee Gas is unable to pass this issuance test, it would need to issue junior debt which would not have the security of the first mortgage bond indenture.

Limitations on Liens

NU’s supplemental indentures under which it issued $175 million in principal amount of 8.58 percent amortizing notes in December 1991 and $75 million in principal amount of 8.38 percent amortizing notes in March 1992 contain restrictions on dispositions of certain NU system companies' stock, limitations of liens on NU assets and restrictions on distributions on and acquisitions of NU stock.  Under these provisions, NU, CL&P, PSNH and WMECO may not dispose of voting stock of CL&P, PSNH or WMECO other than to NU or another NU system company, except that CL&P may sell voting stock for cash to third persons if so ordered by a regulatory agency so long as the amount sold is not more than 19 percent of CL&P's voting stock after the sale.  The restrictions also generally prohibit NU from pledging voting stock of CL&P, PSNH or WMECO or granting liens on its other assets in amounts greater than five percent of the total common equity of NU.  As of December 31, 2004, no NU debt was secured by liens on NU assets.  Furthermore, NU may not declare or make distributions on its capital stock, acquire its capital stock (or rights thereto), or permit an NU system company to do the same, at times when there is an event of default existing under the supplemental indentures under which the amortizing notes were issued.  

The indenture under which NU issued $263 million in principal amount of 7.25 percent notes in April 2002 and $150 million in principal amount of 3.30 percent notes in June 2003 contains a limitation on liens on NU assets and a limitation on sale and leaseback transactions involving those assets.

WMECO's debt indenture, under which it issued $55 million in principal amount of 5.00 percent notes in September 2003 and $50 million in principal amount of 5.90 percent notes in September 2004, contains similar restrictions.

Many of the NU system companies' financing agreements have similar restrictions on liens.

Preferred Stock Issuance Limitations

CL&P’s charter has provisions that prohibit the issuance of additional preferred stock (except for refinancing purposes) unless income before interest charges (as defined and after income taxes and depreciation) is at least 1.5 times the pro-forma annual interest charges on indebtedness and the annual dividend requirements on preferred stock that will be outstanding after the additional stock is issued.  At December 31, 2004, CL&P's income before interest charges was approximately 2.46 times the pro-forma annual interest and preferred dividend requirements.  CL&P has no current plans to issue any preferred stock.

Dividend Payment Limitations

Certain consolidated subsidiaries have dividend restrictions imposed by their long-term debt agreements.  These restrictions also limit the amount of retained earnings available for NU common dividends.  At December 31, 2004, retained earnings available for the payment of dividends totaled $343.5 million.

The Federal Power Act and the 1935 Act limit the payment of dividends by PSNH, CL&P, WMECO and Yankee Gas to retained earnings.  At December 31, 2004, retained earnings for these companies were $243.3 million, $347.2 million, $77.6 million and $52.0 million, respectively.

CL&P's first mortgage bond indenture limits dividend payments and share repurchases to an amount equal to (i) retained earnings accumulated after December 31, 1966; plus (ii) retained earnings accumulated prior to January 1, 1967, not exceeding $13.5 million; plus (iii) any additional amounts authorized by the SEC. Currently, there are no additional amounts authorized by the SEC.

PSNH is also limited by New Hampshire statutes to the payment of dividends not exceeding the amount of retained earnings.

NGC's bond covenants prevent NGC from making dividend payments unless (i) no default or event of default will occur from doing so, (ii) the debt service reserve account has been sufficiently funded with six months of principal and interest on the outstanding bonds, and (iii) the debt service coverage ratio for the previous four fiscal quarters (or, if shorter, since the bond issuance closing date) and projected debt service coverage ratio for the next eight fiscal quarters is greater than or equal to (a) 1.35 if contracted generating capacity is greater than 75 percent or (b) 1.70 if contracted generating capacity is less than 75 percent. At December 31, 2004, NGC's contracted generating capacity was greater than 75 percent.  NGC expects to meet its debt service coverage ratio requirements under this covenant

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and to pay dividends in 2005.

Capitalization

NU and its electric utility subsidiaries are required under the 1935 Act to maintain their consolidated common equity at a level equal to at least 30 percent of their consolidated capitalization.  In planning for the issuance of RRBs and RRCs by CL&P and PSNH in 2001, these companies obtained SEC consent for their common equity ratios to remain below 30 percent through December 31, 2006.  As of December 31, 2004, NU's, CL&P's, WMECO's and PSNH's ratios were 31.9 percent, 28.4 percent, 33.8 percent and 30.4 percent, respectively.  These ratios include RRBs and RRCs as debt.

Credit

NU provides credit assurance in the form of guarantees and letters of credit for the financial performance obligations of certain of its unregulated and regulated subsidiaries.  NU currently has authorization from the SEC to provide up to $750 million of such guarantees for the benefit of its unregulated subsidiaries through June 30, 2007.  As of December 31, 2004, the amount of guarantees outstanding under this limit was $359 million.  NU has also issued indirect guarantees of its regulated companies by issuing guarantees to surety companies.  These guarantees for the regulated companies are subject to a separate $50 million SEC limitation apart from the $750 million guarantee limit.  As of December 31, 2004, $13 million of guarantees were outstanding for the regulated entities.  As of December 31, 2004, NU had $34 million of letters of credit issued for the benefit of the unregulated subsidiaries.

At December 31, 2004, the maximum level of exposure in accordance with FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," (FIN 45), under guarantees by NU, primarily on behalf of NUEI, totaled $1.1 billion.  Computations under FIN 45 include all exposures even though they are not reasonably likely to result in exposure to NU.  

On October 19, 2004, the SEC authorized NU to issue guarantees of up to an aggregate $100 million through June 30, 2007 of the debt or other obligations of two of its subsidiaries, NUSCO and RRR.  These companies provide certain specialized support and real estate services to the entire NU system and occasionally enter into transactions that require financial backing from NU.  The amount of guarantees outstanding in compliance with the SEC limit under this category at December 31, 2004 was $230,000.

Ratings Triggers

Certain NU system credit financing agreements have trigger events tied to the credit ratings of certain NU system companies, as discussed below.

NU and its subsidiaries have $900 million of revolving credit agreements with a number of banks.  There are no ratings triggers that would result in a default, but lower ratings could increase interest on future borrowings from the credit lines.

Select Energy has certain contracts that require the posting of additional collateral in the form of cash or letters of credit in the event NU's ratings were to decline and in increasing amounts dependent upon the severity of the decline.  Select Energy has not had to post any collateral based on NU’s credit downgrades.  Were NU's unsecured ratings to decline two levels to sub-investment grade, Select Energy could, under its present contracts, be asked to provide approximately $361 million of collateral or letters of credit to various unaffiliated counterparties as of December 31, 2004, and approximately $140 million to several independent system operators and unaffiliated local distribution companies as of December 31, 2004, which management believes NU would currently be able to provide.  NU's credit ratings outlooks are currently stable or negative, but management does not believe that at this time there is a significant risk of a ratings downgrade to sub-investment grade levels.  

NGC has a debt reserve account related to its two senior secured debt series that can be funded with cash, an NU guarantee or a letter of credit (LOC) from an acceptable counterparty.  The account may be funded with a guarantee from NU if NU has an investment grade rating by Standard & Poor's and Moody's.  While NU does have investment grade ratings, the debt service reserve account is currently funded with cash.

RRR is a real estate subsidiary that owns NU's Connecticut headquarters site.  As of December 31, 2004, it had approximately $3.8 million of debt outstanding that could be affected by a ratings change.  If NU, CL&P, PSNH or WMECO ratings fall below a B1 Moody's rating or a B+ Standard & Poor's rating, bondholders would have the right to demand mandatory prepayments.

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CONSTRUCTION AND CAPITAL IMPROVEMENT PROGRAM

The NU system's construction program expenditures are estimated to total $740 million in 2005.  Of such total amount, approximately $420 million is expected to be expended by CL&P, $150 million by PSNH, $70 million by Yankee Gas, $40 million by WMECO and up to $60 million by other system entities.  This construction program data includes all anticipated costs necessary for committed projects and for those reasonably expected to become committed projects in 2005, regardless of whether the need for the project arises from environmental compliance, reliability requirements or other causes.  The construction program's main focus is maintaining, upgrading and expanding the existing transmission and distribution system and natural gas distribution system.  The system expects to evaluate its needs beyond 2005 in light of future developments, such as restructuring, industry consolidation, performance and other events.

The $60 million in construction expenditures planned for other system entities in 2005 includes $25 million for NUEI which is mostly due to forecast expenditures at HWP for installation of equipment to meet emission requirements and at NGC's pumped storage and hydroelectric facilities.  

CL&P plans to invest approximately $1.1 billion by the end of 2009 to construct two new 345 KV transmission lines from inland Connecticut to Norwalk, Connecticut and another $60 million to $70 million to replace an existing 138 KV transmission line beneath Long Island Sound.  The investment in transmission lines and continued upgrading of the electric distribution system are expected to increase CL&P's net investment in electric plant by approximately $2.4 billion over the 2005 through 2009 timeframe.  If current plans are implemented on schedule, the NU system would likely require additional external financing to construct these projects.  If all of the transmission projects are built as proposed, the NU system's net investment in electric transmission would increase to nearly $1.9 billion by the end of 2009.  See "Regulated Electric Operations-Connecticut Retail Rates."

Yankee Gas will continue to emphasize system expansion of its natural gas distribution system in Connecticut and has recently received DPUC support for the installation of a 1.2 billion cubic foot liquid natural gas production and storage facility in Waterbury, Connecticut estimated to cost approximately $108 million.  Yankee Gas signed a contract with Chicago Bridge and Iron of The Woodlands, Texas on October 15, 2004 to design and construct the facility.  Construction activities began in March 2004.  See "Connecticut Retail Rates" for information on Yankee Gas' DPUC filing and the related decision.

NUCLEAR ACTIVITIES

General

During 2004, certain NU system companies owned equity interests in three regional nuclear companies (the Yankee Companies) that separately own the Connecticut Yankee nuclear unit (CY), the Maine Yankee nuclear unit (MY), and the Yankee Rowe nuclear unit (Yankee Rowe).  Yankee Rowe, CY and MY have been permanently removed from service and are being decontaminated and decommissioned.

CL&P, PSNH, WMECO and other New England electric utilities are the stockholders of the Yankee Companies.  Each Yankee Company owns a single nuclear generating unit.  The stockholder-sponsors of each Yankee Company are responsible for proportional shares of the operating and decommissioning costs of the respective Yankee Company.  CL&P's, PSNH's and WMECO's stock ownership percentages in the Yankee Companies are set forth below:

CL&P, PSNH and WMECO sold their shares of the Vermont Yankee Atomic Power Corporation (VYNPC), owner of the Vermont Yankee nuclear unit (VY), back to VYNPC in 2003.  Prior to the sale of VY, NU subsidiaries owned 17 percent of VYNPC and, under the terms of the sale, will continue to buy 16 percent of VY’s output through March 2012 at a range of fixed prices.

The NRC has broad jurisdiction over the design, construction and operation of nuclear generating stations, including the decommissioning activities at the Yankee Companies.

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Nuclear Fuel

General

Nuclear fuel costs associated with nuclear plant operations include amounts for disposal of spent nuclear fuel.  The NU system companies include in their nuclear fuel expense those spent fuel disposal costs accepted by the DPUC, NHPUC and DTE in rate case or fuel adjustment decisions.  Spent fuel disposal costs also are reflected in the FERC-approved wholesale charges.

High-Level Radioactive Waste  

The Nuclear Waste Policy Act of 1982 (NWPA) provides that the federal government is responsible for the permanent disposal of spent nuclear reactor fuel (SNF) and other high-level waste.  As required by the NWPA, electric utilities generating SNF and high-level waste are obligated to pay fees into a fund which would be used to cover the cost of siting, constructing, developing and operating a permanent disposal facility for this waste.  The NU system companies have been paying for such services for fuel burned on or after April 7, 1983, on a quarterly basis since July 1983.  The DPUC, NHPUC and DTE permit the fee to be recovered through rates.  For nuclear fuel used to generate electricity prior to April 7, 1983 (prior-period fuel), payment must be made upon the first delivery of spent fuel to the United States Department of Energy (DOE).  The DOE's current estimate for an available site is 2010 at the earliest.

In 2002, Congress designated the Yucca Mountain site in Nevada as the nation's repository for used nuclear fuel.  In return for payment of the fees prescribed by the NWPA, the federal government is to take title to and dispose of the utilities' high-level wastes and SNF.  There have been numerous litigation proceedings involving DOE's statutory and contractual obligation to accept high-level waste and SNF.  While the courts have declined to order the DOE to begin accepting spent fuel for disposal on January 31, 1998, the courts have left open the utilities' ability to bring damage claims against the DOE.

In 1998, YAEC, CYAPC and MYAPC filed separate complaints against the DOE in the United States Court of Federal Claims seeking monetary damages resulting from DOE's failure to accept spent nuclear fuel for disposal.  In decisions later that year, the court found liability on the part of DOE to the companies for breach of the standard contract, based upon DOE's failure to begin disposal of spent nuclear fuel.  The damages owed to YAEC, CYAPC and MYAPC as a result of DOE's failure to begin disposing of spent nuclear fuel is in litigation and the trial addressing these issues concluded on August 31, 2004.  Final post-trial briefs were filed on January 28, 2005.  During the course of the trial the government filed a motion seeking permission to file a counterclaim against CYAPC and MYAPC seeking to offset the pre-1983 monies the companies are holding against any potential damage award in this litigation.  Both MYAPC and CYAPC filed their responses on September 24, 2004.  The court's ruling on that matter is expected to be issued in the same time frame as its overall ruling in the case.

On January 23, 2004, Dominion Nuclear Connecticut, Inc. (DNCI) and Dominion Resources, Inc., on behalf of themselves, CL&P, WMECO and NUSCO, filed a similar complaint in the United States Court of Federal Claims against DOE, with respect to DOE's failure to accept spent nuclear fuel for disposal from the Millstone nuclear power station.  The complaint is subject to an automatic stay imposed by the United States Court of Federal Claims until the lead cases (including the case filed by CYAPC) go to trial on their damages claims.

Until the federal government begins accepting nuclear waste for disposal, nuclear generating plants will need to retain high-level waste and spent fuel onsite or make some other provisions for its storage.

Construction of on-site dry spent fuel storage facilities, to hold the spent nuclear fuel and other high level waste generated at those facilities until the DOE accepts this waste, is complete at Yankee Rowe and MY and in progress at CY.  As of February 1, 2005, 33 of 43 storage canisters have been moved to the dry storage facility site at CY, with targeted completion planned by the summer of 2005.  All of the spent fuel has been transferred to the storage facility at MY as of February 2004.  All of the spent fuel at Yankee Rowe has been moved to the storage site as of June 2003.

Decommissioning

As a result of the sales of Millstone in 2001 and Seabrook and the VY nuclear units in 2002, respectively, NU shareholders, the NU system companies and their ratepayers have no further obligation related to decommissioning with respect to those units.  NU still has significant decommissioning and plant closure cost obligations to the Yankee Companies.  The Yankee Companies collect decommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements to CL&P, PSNH and WMECO and the other non-NU sponsor companies.  These companies in turn pass these costs on to their customers through state regulatory commission-approved retail rates.

During 2002, NU was notified by CYAPC, YAEC and MYAPC that the estimated cost of decommissioning these units and other closure costs increased over prior estimates due to higher anticipated costs for spent fuel storage, security and liability and property

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insurance.  NU's share of these increases is $177.1 million.  

NU cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of these remaining decommissioning and closure costs.  Although management believes that these costs will ultimately be recovered from the customers of CL&P, PSNH and WMECO, there is a risk that the FERC may not allow these costs, the estimates of which have increased significantly since 2002, to be recovered in wholesale rates.  If the FERC does not allow these costs to be recovered in wholesale rates, NU would expect the state regulatory commissions to disallow those costs in retail rates as well.  As owners of equity investments in CYAPC, CL&P, PSNH and WMECO are subject to losses if CYAPC is not successful in rate proceedings at the FERC.

YAEC, MYAPC and CYAPC are currently collecting revenues for the decommissioning of the related sites through their power purchase agreements.  YAEC ceased decommissioning collections in June 2000 but began collections again on June 1, 2003.  The table below sets forth the NU system companies' estimated share of remaining decommissioning costs of the Yankee Companies' units as of December 31, 2004, net of amounts collected in rates.  The estimates are based on the latest decommissioning cost estimates.  For information on the equity ownership of the NU system companies in each of the Yankee Companies' units, see "Nuclear Activities-General."

* The costs shown include the expected future revenue requirements associated with the funding of decommissioning, recovery of remaining assets and other closure costs associated with the early retirement of Yankee Rowe, CY and MY as of December 31, 2004, which have been recorded as an obligation on the books of the NU system companies.

As of December 31, 2004, the Yankee Companies' share of the external decommissioning trust fund balances (at market), reflecting the contribution share provided by the NU system companies, is as follows:

CYAPC's estimated decommissioning and plant closure costs for the period 2000 through 2023 have increased by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement.  On July 1, 2004, CYAPC filed with the FERC for recovery of these increased costs.  In the filing, CYAPC sought to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on January 1, 2005.  On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund, and scheduled hearings for May 2005.  Related hearings associated with actions brought by certain interveners are currently ongoing.  For further information on this proceeding, see Item 3, "Legal Proceedings."

YAEC filed with the FERC in April 2003 for its unrecovered decommissioning costs.  A settlement was approved by the FERC on October 2, 2003 and collections began on June 1, 2003.  YAEC is to return to the FERC in 2006 to update its estimate.  MYAPC filed with the FERC in October 2003 for new rates and reached a settlement with the FERC and intervening parties in September 2004 for total annual collections of approximately $27 million annually through October 2008.  

In June 2003, CYAPC terminated its contract with Bechtel Power Corporation (Bechtel) for the decommissioning of CY.  For information on litigation between CYAPC and Bechtel relating to the termination of this contract, see Item 3, "Legal Proceedings."

In October 2001, NU issued a report, following an extensive search, concerning two missing fuel pins at the retired Millstone 1 nuclear unit which was subsequently sold to DNCI.  As of December 31, 2004, costs related to this search totaled $9.4 million.  The report concluded that the pins are currently located in one of four facilities licensed to store low or high-level nuclear waste and that they are not a threat to public health and safety.  A follow-up inspection by the NRC concluded that NU's investigation was thorough and complete and its conclusions were reasonable and supportable.  These events resulted in the issuance of an NRC notice of violation and the imposition of a $288,000 civil penalty in 2002.  The NRC concluded its review of this matter in April 2004, stating that additional efforts to locate the rods were unwarranted.

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OTHER REGULATORY AND ENVIRONMENTAL MATTERS

Environmental Regulation

General

The NU system and its subsidiaries are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters.  Additionally, the NU system's major generation and transmission facilities may not be constructed or significantly modified without a review by the applicable state agencies of the environmental impact of the proposed construction or modification.  Compliance with increasingly more stringent environmental laws and regulations, particularly air and water pollution control requirements, may limit operations or require substantial investments in new equipment at existing facilities.

Surface Water Quality Requirements

The federal Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the United States Environmental Protection Agency (EPA) or state environmental agency specifying the allowable quantity and characteristics of its effluent.  States may also require additional permits for discharges into state waters.  NU system facilities are in the process of obtaining or renewing all required NPDES or state discharge permits in effect.  Compliance with NPDES and state discharge permits has necessitated substantial expenditures, which are difficult to estimate, and may require further significant expenditures because of additional requirements or restrictions that could be imposed in the future, including requirements related to Sections 316(a) and 316(b) of the Clean Water Act for facilities owned by PSNH and HWP.  For information regarding civil lawsuits related to alleged violations of certain facilities' NPDES permits, see Item 3, "Legal Proceedings."

The Federal Oil Pollution Act of 1990 (OPA 90) sets out the requirements for facility response plans and periodic inspections of spill response equipment at facilities that can cause substantial harm to the environment by discharging oil or hazardous substances into the navigable waters of the United States and onto adjoining shorelines.  The NU system companies are currently in compliance with the requirements of OPA 90.  OPA 90 includes limits on the liability that may be imposed on persons deemed responsible for release of oil.  The limits do not apply to oil spills caused by negligence or violation of laws or regulations.  OPA 90 also does not preempt state laws regarding liability for oil spills.  In general, the laws of the states in which the NU system owns facilities and through which the NU system transports oil could be interpreted to impose strict liability for the cost of remediating releases of oil and for damages caused by releases.  The NU system currently carries general liability insurance in the total amount of $160 million annual coverage, which includes liability coverage for oil spills.

Air Quality Requirements

The Clean Air Act Amendments of 1990 (CAAA), as well as state laws in Connecticut, Massachusetts and New Hampshire, impose stringent requirements on emissions of sulfur dioxide (SO2) and nitrogen oxide (NOX) for the purpose of controlling acid rain and ground level ozone.  In addition, the CAAA address the control of toxic air pollutants.  Installation of continuous emissions monitors and expanded permitting provisions also are included.  Compliance with CAAA requirements cost the NU system approximately $24 million during 2004: approximately $21 million for PSNH and approximately $3 million for HWP.  

Massachusetts and New Hampshire are both imposing significant new emission reduction requirements on power plants, in addition to the Federal requirements.  In Massachusetts, new emission standards for power plants were signed into law in September 2001. The four pollutants regulated under these standards are NOX, SO2, carbon dioxide (CO2) and mercury, with some limits and requirements effective in October 2006 and other limits and requirements effective in 2008 and 2012.  Interim limits for NOX and SO2 were also set for HWP.  The mercury standards were finalized in June 2004.  The capital cost for Mt. Tom Station to meet current and known future Massachusetts emission reduction limits and requirements is estimated to be approximately $14 million if a selective catalytic reduction (SCR) system is installed to meet the new emission standards.  Completion of this work will reduce Mt. Tom's NOX emissions, thus lowering the amount of NOX allowances required compared to prior years.  SO2 requirements will be met by purchasing lower sulfur coals.  Additional costs for compliance with mercury requirements are unknown at this time.

In New Hampshire, the Multiple Pollutant Reduction Program was signed into law in May 2002.  This law addresses emissions reductions of the same four pollutants as in Massachusetts.  NOX, SO2 and CO2 have their emission caps established for current compliance beginning in 2007.  The mercury emission cap is expected to be considered by the legislature by July 1, 2005.  Estimates for additional compliance costs (excluding mercury control) are between $20 and $25 million dollars and will be better known after the mercury reduction requirement is established.

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Hazardous Materials Regulations

As many other industrial companies have done in the past, the NU system companies disposed of residues from operations by depositing or burying such materials on-site or disposing of them at off-site landfills or facilities.  Typical materials disposed of include coal gasification waste, fuel oils, ash, gasoline and other hazardous materials that might contain polychlorinated biphenyls (PCBs).  It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks.  The NU system has recorded a liability for what it believes is, based upon currently available information, its estimated environmental investigation and/or remediation costs for waste disposal sites for which the NU system companies expect to bear legal liability, and continues to evaluate the environmental impact of its former disposal practices.  Under federal and state law, government agencies and private parties can attempt to impose liability on NU system companies for such past disposal.  At December 31, 2004, the liability recorded by the NU system for its estimated environmental remediation costs for known sites needing investigation and/or remediation, including those sites described below, exclusive of recoveries from insurance or from third parties, was approximately $38.7 million, representing 53 sites.  This total includes liabilities recorded by Yankee Gas of approximately $19.1 million.  All cost estimates were made in accordance with generally accepted accounting principles where investigation and/or remediation costs are probable and reasonably estimable.  These costs could be significantly higher if additional remedial actions become necessary.  These liabilities break down as follows:

1. Under the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, commonly known as Superfund, EPA has the authority to clean up or order the clean up of hazardous waste sites and to impose the clean up costs on parties deemed responsible for the hazardous waste activities on the sites.  Responsible parties include the current owner of a site, past owners of a site at the time of waste disposal, waste transporters and waste generators.  As of December 31, 2004, the NU system was involved in five Superfund matters: one in Connecticut, one in New Jersey, two in New Hampshire and one in Kentucky, which could have a material impact on the NU system.  The NU system has established a reserve of approximately $1.1 million for its share of the clean up of these sites.  For further information on litigation relating to the Connecticut matter, see Item 3, "Legal Proceedings."

2. The greatest liabilities currently relate to former manufactured gas plant (MGP) facilities which represent the largest share of future clean up costs.  These facilities were owned and operated by predecessor companies to the NU system from the mid-1800's to mid-1900.  Byproducts from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose risks to human health and the environment.  The NU system currently has partial or full ownership responsibilities at 29 former MGP sites.  Of the total NU system liabilities, a reserve of approximately $33.2 million has been established to address future investigation and/or remediation costs at MGP sites.

3. Other sites undergoing and/or anticipating comprehensive investigations or remediation actions under state programs located in Connecticut, Massachusetts or New Hampshire include two former fuel oil releases, two landfills, three asbestos hazard abatement projects and twelve miscellaneous projects.  To date, a reserve of approximately $4.5 million has been established to address future investigation and/or remediation costs at these sites.

In the past, the NU system has received other claims from government agencies and third parties for the cost of remediating sites not currently owned by the NU system but affected by past NU system disposal activities and may receive more such claims in the future.  The NU system expects that the costs of resolving claims for remediating sites about which it has been notified will not be material, but cannot estimate the costs with respect to sites about which it has not been notified.

For further information on environmental liabilities, see Footnote 6B, "Commitments and Contingencies – Environmental Matters" contained within NU’s 2004 Annual Report to Shareholders, which is incorporated into this Form 10-K by reference.

Electric and Magnetic Fields

Published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes.  Most researchers, as well as numerous scientific review panels considering all significant EMF epidemiological and laboratory studies to date, agree that current information remains inconclusive, inconsistent and insufficient for characterizing EMF as a health risk.

Based on this information, management does not believe that a causal relationship between EMF exposure and adverse health effects has been established or that significant capital expenditures are appropriate to minimize unsubstantiated risks.  The NU system companies have closely monitored research and government policy developments for many years and will continue to do so.

If further investigation were to demonstrate that the present electricity delivery system is contributing to increased risk of cancer or other health problems, the industry could be faced with the difficult problem of delivering reliable electric service in a cost-effective manner while managing EMF exposures.  To date, no courts have concluded that individuals have been harmed by EMF from electric utility facilities, but if utilities were to be found liable for damages, the potential monetary exposure for all utilities, including the NU

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system companies, could be enormous.  Without definitive scientific evidence of a causal relationship between EMF and health effects, and without reliable information about the kinds of changes in utilities' transmission and distribution systems that might be needed to address the problem, if one is found, no estimates of the cost impacts of remedial actions and liability awards are available.

In addition, the CSC held hearings in January 2005 to assess proposals for mitigating EMF associated with certain of NU’s proposed new overhead transmission lines.  For information on these hearings, see "Regulated Electric Operations – Connecticut Retail Rates – CL&P Transmission Projects."

FERC Hydroelectric Project Licensing

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

The NU system companies currently hold the FERC licenses for 11 hydroelectric projects totaling 16 plants.  In addition, the NU system companies own and operate five unlicensed hydroelectric projects that are currently deemed non-jurisdictional by the FERC.  These licensed and unlicensed hydroelectric projects are located in Connecticut, Massachusetts and New Hampshire and aggregate approximately 1,367 MW of capacity.  NGC owns four licensed and four unlicensed projects with approximately 1,296 MW capacity.  PSNH owns nine hydroelectric generating stations with an aggregate of approximately 68.1 MW of capacity.

On June 23, 2004 a single, new 40-year license was issued to NGC for the 109.8 MW Housatonic hydroelectric project and the 11 MW Falls Village project.  The new license incorporates the terms and conditions of the CDEP 401 water quality certification.  The license and water quality certificate require operation of the Falls Village and Bulls Bridge projects in run of river mode and specify minimum flow releases for the by pass reaches at these projects, and minimum flow releases at the Stevenson project and Shepaug projects.  Upstream and downstream fish passage facilities for the Stevenson project must be designed by 2011 and constructed by 2014.  Fish passage facilities for the Shepaug and Bulls Bridge projects must be designed by 2021 and completed by 2024.  Interim upstream eel passage facilities at the Stevenson project must be operational in 2005.  The license also requires that NGC prepare and implement a number of project plans, including recreation, shoreline management, critical habitat management, debris management, nuisance plant monitoring and historic property management plans.  

PSNH's FERC license for the Merrimack River Hydroelectric Project that consists of the Amoskeag, Hooksett and Garvins Falls hydroelectric generating stations expires on December 31, 2005.  In December 2003, PSNH filed an application for a new license for the project.  The FERC's most recent relicensing schedule provides for issuance of notice that the application is ready for environmental review in March 2005; availability of an environmental assessment in August 2005 and readiness for commission decision in November 2005.  If a new license is not issued by the expiration of the current license (December 31, 2005), it is expected that the FERC will issue an annual license for the project.  Annual licenses are commonly issued under the same terms and conditions as the current license, but may include new conditions if such conditions are authorized by the existing license.

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

At this time, it appears unlikely that the FERC will order decommissioning of NGC or PSNH hydroelectric projects at relicensing or that the projects will be abandoned, surrendered or the project licenses revoked.  However, it is impossible to predict the outcome of the FERC relicensing proceedings with certainty, or to determine the impact of future regulatory actions on project economics.  Until such time as a project is ordered to be decommissioned and the terms and conditions of a decommissioning order are known, it is not possible to accurately estimate or predict the cost of project decommissioning.

EMPLOYEES

As of December 31, 2004, the NU system companies had 7,079 employees on their payrolls, excluding temporary employees, of which 2,239 were employed by CL&P, 1,297 by PSNH, 409 by WMECO, 472 by Yankee Gas, 229 by NGS, 1,571 by NUSCO, 170 by Select, 123 by SESI, 521 by SECI, 24 by Boulos, 10 by Woods Electric and 14 by Woods Network.  NU, NGC, NAEC, Mode 1 and NUEI have no employees.  There could be some impact on employees at the competitive wholesale and services businesses due to NU's March 9, 2005 decision to exit those businesses.

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Approximately 2,450 employees of CL&P, PSNH, WMECO, HWP, NGS and Yankee Gas are covered by 15 union agreements.  In 2004, five contracts were negotiated (including three major physical worker contracts in Connecticut and Western Massachusetts) which are expected to result in labor stability through 2009 and 2010, respectively.  In addition to the continuing negotiation of several smaller contracts from 2004, NU expects to negotiate two Yankee Gas contracts and two dispatcher contracts in the summer and fall of 2005, respectively.

INTERNET INFORMATION

The NU system's Web site address is http://www.nu.com/investors.  The company makes available through its Web site a link to the SEC's EDGAR site, at which site NU's, CL&P's, WMECO's and PSNH's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports may be reviewed.  Printed copies of these reports may be obtained free of charge by writing to the Company's Investor Relations Department at Northeast Utilities, 107 Selden Street, Berlin, Connecticut 06037.

Item 2.

Properties

The physical properties of NU are owned or leased by subsidiaries of NU.  CL&P's properties are located either on land which is owned in fee or on land, as to which CL&P owns perpetual occupancy rights adequate to exclude all parties except possibly state and federal governments, which has been reclaimed and filled pursuant to permits issued by the United States Army Corps of Engineers.  The principal properties of PSNH are held by it in fee.  A major portion of WMECO's properties are owned in fee.  In addition, CL&P, PSNH and WMECO lease certain data processing equipment, vehicles, and office space.  Also CL&P and WMECO lease certain substation equipment.  With few exceptions, NU's lines are located on or under streets or highways, or on properties either owned or leased, or in which they have appropriate rights, easements, licenses or permits from the owners or the appropriate governmental authorities.

Yankee Gas' property consists primarily of its natural gas distribution facilities including distribution lines (mains and services), meters, valves, pressure regulators and flow controllers.  Yankee Gas also owns five propane peak-shaving facilities with a combined storage capacity equivalent to approximately 206,000 million cubic feet and service buildings and rents or leases certain other property.  Yankee Gas plans to remove one of the propane peak shaving facilities from service in 2005 which will reduce the combined storage capacity to 170,000 million cubic feet.  

CL&P, PSNH, WMECO, NGC and Yankee Gas' properties are subject to the lien of each company's respective first mortgage indentures.  In addition, CL&P's interest in transmission assets is subject to a second mortgage lien for the benefit of the PCRBs.  Various properties are also subject to minor encumbrances which do not substantially impair the usefulness of the properties to the owning company.  

NU's properties are well maintained and are in good operating condition.

Transmission and Distribution System

At December 31, 2004 NU owned 109 transmission and 340 distribution substations that had an aggregate transformer capacity of 18,177,573 kilovoltamperes (kVa) and 9,107,163 kVa, respectively; 3,081 circuit miles of overhead transmission lines ranging from 69 kilovolt (kV) to 138 kV, and 196 cable miles of underground transmission lines ranging from 69 kV to 138 kV; 2,623 pole miles of overhead and 44 conduit bank miles of underground distribution lines; and 458,390 line transformers in service with an aggregate capacity of 20,899,000 kVa.

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Electric Generating Plants

As of December 31, 2004, the electric generating plants of NU were as follows:  

*Claimed capability represents winter ratings as of December 31, 2004.

Franchises

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

In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth in Title 16 of the Connecticut General Statutes and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and/or sell electricity at retail, including to provide transitional standard offer, backup, and default service, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law.  The franchises of CL&P include the power of eminent domain.  Title 16 of the Connecticut General Statutes was amended, however, by Public Act 03-135, "An Act Concerning Revisions to the Electric Restructuring Legislation," to prohibit an electric distribution company from owning or operating generation assets.  CL&P has divested all of its generation assets and is now acting as a transmission and distribution company.  See "Regulated Electric Operations - Rates - General" for more information on electric industry restructuring.  

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

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

WMECO - WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines.  Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted

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are not vested.  Such locations are for specific lines only, and for extensions of lines in public highways, further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities.  In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority and pursuant to state laws, has the power of eminent domain.   

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

HWP and HP&E - HWP, and its wholly owned subsidiary HP&E, are authorized by their charters to conduct their businesses in the territories served by them.  HWP's electric business is subject to the restriction that sales be made by written contract in amounts of not less than 100 horsepower to purchasers who use the electricity in their own business in the counties of Hampden or Hampshire, Massachusetts and cities and towns in these counties, and customers who occupy property in which HWP has a financial interest, by ownership or purchase money mortgage. The two companies have locations in the public highways for their transmission and distribution lines.  Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested.  Such locations are for specific lines only and, for extensions of lines in public highways, further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities.  HP&E has no retail service territory area and sells electric power exclusively at wholesale.  In connection with the sale of certain of HWP's and HP&E's assets to the city of Holyoke Gas and Electric Department (HG&E) effective December 2001, HWP agreed to cause the charters of HWP and HP&E to be amended to eliminate their rights to distribute electricity at retail in Holyoke and surrounding towns unless other sellers can legally compete with HG&E, and not to exercise such rights prior to such amendment.

NGC - NGC is an exempt wholesale generator (EWG) and, as it currently operates its business, is not regulated by the DPUC or the DTE.  The FERC's authorization for EWGs such as NGC to sell wholesale electric power at market-based rates typically contains an exemption from much of the traditional public utility company rate regulation.  As an EWG, NGC is a "public utility" subject to the Federal Power Act.  The market-based rate authorization that NGC has received from the FERC exempts NGC from some, but not all, of Federal Power Act regulations, including traditional cost-based rate regulation.  However, NGC is required to file summary information concerning its power transactions on a quarterly basis with FERC.

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

Item 3.

Legal Proceedings

1.

Consolidated Edison, Inc. v. NU - Merger Related Litigation and Appeal

On March 5, 2001, Con Edison advised NU that it was unwilling to close its then-pending merger with NU on the terms set forth in the parties' merger agreement dated October 13, 1999 (the Merger Agreement).  That same day, NU notified Con Edison that it would treat Con Edison's refusal to proceed with the merger as a repudiation and breach of the Merger Agreement and would file suit to obtain the benefits of the transaction for NU shareholders.

On March 6, 2001, Con Edison filed suit in the United States District Court for the Southern District of New York (the District Court) seeking a declaratory judgment that it had been relieved of its obligation to proceed with the merger due to, among other things, NU's alleged breach of the Merger Agreement and the alleged occurrence of a "Material Adverse Change" with respect to NU, as that term is defined in the Merger Agreement.  On March 12, 2001, NU filed suit against Con Edison in the District Court seeking damages in excess of $1 billion arising from Con Edison's breach of the Merger Agreement.

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On May 11, 2001, Con Edison filed an amended complaint in the action it had commenced on March 6, 2001, in which it added claims seeking damages for breach of contract, fraudulent inducement and negligent misrepresentation in an unspecified amount, but which Con Ed's Chief Financial Officer has since testified is at least $314 million.  On June 1, 2001, NU answered Con Edison's amended complaint, denying all of its material allegations and asserting affirmative defenses, and asserted a counterclaim seeking damages in excess of $1 billion against Con Edison for breach of the Merger Agreement.  NU subsequently dismissed its March 12 complaint, without prejudice, since it was duplicative of the June 1 counterclaim filed in the Con Edison action.  On June 8, 2001, Con Edison answered NU's counterclaim, denying its material allegations and asserting affirmative defenses.

The companies completed discovery in the litigation in 2002 and filed cross motions for summary judgment, which were decided by the District Court on March 14, 2003.  The District Court granted NU's motion for summary judgment dismissing Con Edison's fraud and negligent misrepresentation claims, but in all other respects denied both parties' motions.  Among other things, the District Court rejected Con Edison's argument that NU could not sue to recover the more than $1 billion merger premium on behalf of its shareholders, and held that NU shareholders were intended third-party beneficiaries of the Merger Agreement and that NU could sue to recover the merger premium on their behalf.

On July 24, 2003, Robert Rimkoski (Rimkoski), an alleged former NU shareholder who held NU common shares on March 5, 2001 (the day Con Edison repudiated the Merger Agreement) but sold them two days later, moved to intervene in the action on behalf of a putative class consisting of all persons who held NU shares on March 5, 2001, claiming that such persons and not NU's current shareholders are the proper third-party beneficiaries of the Merger Agreement and are entitled to any recovery awarded as a result of Con Edison's breach of the Merger Agreement. NU opposed Rimkoski's motion to intervene on the ground that he lacked standing.  NU contended that the right to claim the merger premium, and the related right to sue for breach of the Merger Agreement, "ran with" NU shares and were thus sold by Rimkoski when he sold his NU shares, and that accordingly only current NU shareholders could assert a claim for the merger premium.

On December 24, 2003, the District Court granted Rimkoski's motion to intervene in the lawsuit as a defendant, but deferred a decision on the issue of whether Rimkoski's putative class of March 5, 2001 shareholders or NU's current shareholders are the proper third-party beneficiaries of the Merger Agreement.  On January 5, 2004, NU filed a cross-claim against Rimkoski seeking a declaratory judgment that NU's current shareholders and not Rimkoski's putative class of March 5, 2001 shareholders are the proper third-party beneficiaries of the Merger Agreement.

In March 2004, NU moved for summary judgment on its cross-claim against Rimkoski.  At the same time, Con Edison moved to dismiss NU's counterclaim against it, to the extent it sought damages on behalf of its current shareholders, arguing that only NU shareholders on March 5, 2001, such as Rimkoski, owned the right to pursue the third-party beneficiary contract claim against Con Edison. Rimkoski joined in Con Edison's motion.

In an order dated May 15, 2004, the District Court denied NU's motion for summary judgment on its cross-claim against Rimkoski and granted Con Edison's motion, holding that the claim for breach of the Merger Agreement belonged to NU shareholders as of March 5, 2001.  However, recognizing that there was no precedent addressing this complex issue, the District Court sua sponte certified this issue for interlocutory review by the Second Circuit Court of Appeals (the Second Circuit) pursuant to 28 U.S.C. § 1292(b).  The District Court also certified for interlocutory review its ruling, in its summary judgment opinion dated March 14, 2003, that NU shareholders were third-party beneficiaries of the Merger Agreement entitled to pursue a damage claim against Con Edison for the merger premium.  In an order dated October 20, 2004, the Second Circuit agreed to review both issues certified by the District Court.

Briefing of the issues pending in the Second Circuit was completed in mid-February 2005.  No date has yet been set by the Second Circuit for oral argument.

The District Court has not set a trial date in this action, and it is not possible to predict either the outcome or the ultimate effect on NU of any of the claims asserted by any of the parties thereto.

2.

Sale of Millstone to Dominion Nuclear Connecticut Inc.

On March 8, 2001, the Connecticut Coalition Against Millstone (CCAM) and other parties filed a lawsuit in Connecticut Superior Court against the CDEP, NNECO and DNCI challenging (1) the validity of Millstone's NPDES permit (Permit) and a previously issued CDEP emergency authorization allowing Millstone to discharge wastewater not expressly authorized by the facility's Permit and (2) CDEP's authority to transfer both Millstone's permit and emergency authorization to DNCI.  On March 29, 2001, CCAM's request for a temporary restraining order enjoining CDEP from transferring both the Permit and emergency authorization to DNCI prior to a full hearing was denied.  Subsequently, on July 19, 2001, the entire matter was dismissed.  On September 20, 2002, the Connecticut Supreme Court assigned the matter to itself.  On December 23, 2003, the Connecticut Supreme Court dismissed CCAM's appeal.  On January 2, 2004, CCAM filed a motion for reconsideration en banc, which was denied on February 4, 2004.

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3.

Retirement Plan Litigation

This matter involves four separate but related federal court lawsuits brought by nineteen former employees of NUSCO, WMECO and CL&P who retired between 1991 and 1994.  The complaints generally allege that the companies breached their fiduciary duties to the plaintiffs by making affirmative misrepresentations that caused them to retire prematurely, since as a result of these alleged misrepresentations they came to believe incorrectly that no particular future enhancement of employee benefits was being seriously considered at the time by the companies.  Plaintiffs are seeking the benefits of retirement plan enhancements adopted subsequent to their retirements.

The cases were tried together in a summary bench trial in the United States District Court in Hartford, Connecticut in April-May 2002.  In a ruling issued on April 1, 2004, the judge found in favor of 15 of the19 plaintiffs and ordered NU to modify its retirement plan so as to include the successful plaintiffs in the special retirement plans at issue, retroactive to the dates of their retirement.  NU withdrew its appeal of the court’s decision, and reached a settlement with plaintiffs over interest and attorney’s fees.

For further information on retirement-related matters, see Part I, Item 2, Note 4, of the "Notes to Consolidated Financial Statements."

4.

Wisvest-Connecticut, LLC (Wisvest) v. Select Energy, Inc. and PSEG Power Connecticut LLC   v. NU

Wisvest filed suit in July 2002 against Select Energy in the Superior Court at New Britain, Connecticut.  In its complaint, Wisvest alleges that Select Energy breached its Load Asset Contract for Electrical Load dated November 23, 1999 (the Agreement), which contract expired on December 31, 2003, by unilaterally reducing the amount of electricity it proposed to purchase from Wisvest.  The complaint seeks monetary damages and a declaratory judgment.  Wisvest’s claim against Select Energy is expected to be withdrawn as the price Wisvest was paid for the power not purchased by Select Energy was higher than what Select Energy paid under the Agreement.  

Select Energy has filed an Answer to the complaint, denying any liability.  It has also filed several special defenses and counterclaims to recover approximately $5.8 million plus interest for congestion charges incurred and paid by Select Energy prior to the implementation of SMD on March 1, 2003.  Select Energy, pursuant to the contract, ultimately withheld from a final payment to Wisvest (now known as PSEG Power Connecticut LLC) approximately $6.5 million for the pre-SMD congestion and interest charges.

In a separate but related claim, PSEG Power Connecticut LLC brought suit against NU seeking to recover the $6.5 million withheld by Select Energy under an NU parent guaranty.  The cases have been consolidated on the complex litigation docket in Connecticut Superior Court, where NU’s discovery is currently underway.  PSEG Power Connecticut LLC has moved for summary judgment on the parent guaranty; however, consideration of the motion was stayed by the court pending completion of discovery by Select Energy.  Oral argument on PSEG Power Connecticut LLC’s motion will be heard in April 2005.  No trial date has been set.  

5.

Constellation Power Source, Inc. (Constellation) v. Select Energy, Inc.

This case involves a dispute between Select Energy and Constellation over responsibility for socialized congestion charges imposed by ISO-NE prior to the implementation of Standard Market Design (SMD) on March 1, 2003, and who is responsible for congestion and losses following implementation of SMD.  Constellation filed a complaint in the U.S. District Court for the District of Connecticut against Select Energy claiming that Select Energy was responsible for pre- and post-SMD congestion and losses amounting to approximately $9.7 million.  Select Energy filed a counterclaim seeking to recover the $2.5 million in pre-SMD charges that Constellation has refused to pay.  The case is in the discovery phase with dispositive motions scheduled to filed by the Spring 2005.

6.

NRG Bankruptcy

On May 14, 2003, NRG and certain of its affiliates filed for Chapter 11 protection in the United States Bankruptcy Court for the Southern District of New York (Bankruptcy Court).  The filing affects relationships between various NU companies and the NRG companies.

A.

Station Service

NRG has disputed its responsibility to pay for the provision of station service by CL&P to NRG's Connecticut generating plants.  The FERC issued a decision on December 20, 2002 that NRG had agreed that station service from CL&P would be subject to CL&P's applicable retail rates, and that states (i.e., the DPUC) have jurisdiction over the delivery of power to end users even where, as here, power is not delivered via distribution facilities.  NRG refused CL&P's subsequent demand for payment, and on April 3, 2003, CL&P petitioned the DPUC for a declaratory order enforcing the FERC's December 20, 2002 decision.  Prior to the issuance of a decision by the DPUC, NRG filed a petition under Chapter 11 of the U.S. Bankruptcy Code, staying any further action by the DPUC.

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On September 9, 2003, the Bankruptcy Court approved the parties' stipulation to submit the station service issue to arbitration for a determination of liability and damages which will fix CL&P's claim in bankruptcy.  The parties are currently pursuing arbitration of the issues in dispute but no hearing dates have been scheduled.  On December 17, 2003, the DPUC issued a decision in CL&P's rate case that addressed the issue that CL&P had first raised to the DPUC in its April 3, 2003 filing.  The DPUC affirmatively stated that CL&P has been appropriately administering its station service rates.  Subsequently, however, in unrelated proceedings, the FERC issued a series of orders with conflicting policy direction, which call into question its December 20, 2002 NRG order.  

B.

Yankee Gas

On October 9, 2002, NRG informed Yankee Gas that its affiliate, Meriden Gas Turbines, LLC (MGT) was permanently shutting down or abandoning its Meriden power plant project, and requested that Yankee Gas cease its construction activities and begin an orderly wind down of its work relating to the project.  Based on NRG's statement that it expected that Yankee Gas would draw on a $16 million LOC, Yankee Gas drew down the full amount of the LOC.  On November 12, 2002, MGT filed suit against Yankee Gas in Meriden Superior Court, claiming that Yankee Gas breached the agreement with MGT (MGT Agreement) and seeking a declaratory ruling from the court that Yankee Gas wrongfully drew down the $16 million LOC.  In April 2003, Yankee Gas filed its answer to MGT's complaint and asserted several counterclaims to recover its losses arising out of MGT's termination of the MGT Agreement.

Yankee Gas has filed an amended answer and counterclaim and an application for a prejudgment remedy (PJR) seeking to attach sufficient assets to secure a judgment on Yankee Gas’ counterclaims and a preliminary injunction seeking to enjoin a sale of MGT’s assets, including the MGT project itself.  Hearings were held on Yankee Gas’ applications and the court ordered the parties to participate in mediation, which was held on September 21, 2004.  The mediation was unsuccessful and on October 7, 2004, the court denied Yankee Gas’ application for a PJR and preliminary injunction.  Expert witness discovery is ongoing.  Trial is expected to begin in May 2005.

C.

Congestion Charges

On August 5, 2002, CL&P withheld the past due congestion charges from its payment to NRG pursuant to contractual provisions allowing the withholding of disputed sums.  CL&P continued to withhold congestion charges from its monthly payments to NRG, through March 1, 2003.  On November 28, 2001, CL&P filed a complaint against NRG in Connecticut Superior Court alleging breach of contract arising from the failure of NRG to pay socialized congestion charges.  The case was removed to U.S. District Court for the District of Connecticut.  NRG filed a counterclaim seeking recovery of all amounts CL&P has withheld.  Discovery is complete and CL&P’s motion for summary judgment is pending.  No trial date is currently scheduled.

For additional information on NRG-related matters, see Item 1,  "Business - Rates - Connecticut Retail Rates."

7.

Hawkins, Delafield & Wood (Hawkins) v. NU, NUSCO and CL&P

On December 12, 2002, Hawkins, a New York law firm sued by the Connecticut Resources Recovery Authority (CRRA) as a result of the Enron bankruptcy brought an apportionment complaint against a number of former Enron officers, directors and outside accountants.  In addition to the Enron defendants, Hawkins also named as defendants in its complaint NU, NUSCO and CL&P.  Hawkins asserts in its complaint that in the event it is found liable to CRRA, then the apportionment defendants, including NU, NUSCO and CL&P, are responsible for some or all of the $220 million claimed as damages.

The case is proceeding along three broad tracks: (a) an attempt by various defendants to persuade the Multi-District Litigation (MDL) Judicial Panel to transfer the case to the United States District Court for the Southern District of Texas; (b) an attempt to consolidate this case with a case now pending, which itself is subject to a conditional order of the MDL Judicial Panel transferring it to the Southern District of Texas; and (c) an attempt to remand this case to Connecticut's state court.  No further action in this case is anticipated until the MDL Judicial Panel rules, as the United States District Court judge has stayed all proceedings pending such ruling.  The NU defendants had not yet responded to the apportionment complaint at the time the proceedings were stayed.

8.

Environmental Litigation

On September 25, 2002, NUSCO, among other defendants, was sued by the Joseph A. Schiavone Corporation (Schiavone) under the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (Superfund) for the costs associated with the investigation and remediation of a commercial property owned by Schiavone in North Haven, Connecticut.  Schiavone alleges that from 1968 through 1978, NUSCO sold transformers containing PCBs to a company named H. Kasden & Sons, a co-defendant, which owned the property before Schiavone and operated a scrap yard at the site.  The property is currently involved in an EPA and CDEP monitored investigation and remediation of PCB contamination and related costs are estimated at approximately $4 million.  On June 6, 2003, CL&P was added as a defendant.

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On December 13, 2004, the U.S. Supreme Court ruled, in an unrelated case, Cooper Industries Inc. v. Aviall Services Inc., that contribution actions under Section 113(f)(1) of Superfund required a prior governmental civil action against the party seeking contribution.  This development directly impacted plaintiff’s claim against NUSCO/CL&P, since plaintiff had not been subject to a prior governmental civil action.  As a direct result, a scheduled January 6, 2005 mediation was cancelled, discovery was suspended, and a Stipulation of Dismissal was filed on January 19, 2005.  NUSCO and CL&P are evaluating their options for resolving their dispute with plaintiff in the wake of these events.

9.

 CYAPC Decommissioning Dispute

A.

Bechtel Power Corporation Litigation

On June 13, 2003, CYAPC gave notice of the termination of its contract with Bechtel for the decommissioning of the Connecticut Yankee nuclear power plant, due to Bechtel's history of incomplete and untimely performance and refusal to perform the remaining decommissioning work.

Bechtel has filed a complaint against CYAPC in Connecticut Superior Court.  Bechtel’s complaint asserts claims for breach of contract, negligent misrepresentation, commercial impracticability, breach of CYAPC’s duty of good faith and fair dealing, wrongful termination, and violation of the Connecticut Unfair Trade Practices Act (CUTPA).  On August 22, 2003, CYAPC filed its answer and counterclaims, including counts for breach of contract, negligent misrepresentation and breach of duty of good faith and fair dealing.  Discovery is ongoing and a trial has been scheduled for May 2006.  

On June 18, 2004, Bechtel requested the court to grant a prejudgment remedy in the amount of $93.5 million by garnishing CYAPC’s assets, the CYAPC shareholders contributions to the decommissioning trust, and proceeds of DOE litigation.  

On October 27, 2004, Bechtel and CYAPC entered into an agreement under which Bechtel relinquished its right to seek garnishment of the decommissioning trusts and related payments, in return for the potential attachment of CYAPC’s real property, and an amount totaling $41.7 million (representing shareholder equity) that the sponsors would pay into a separate escrow account through June 30, 2007.  CYAPC has continued to contest the attachability of these remaining assets, and the court has not yet ruled on that issue.

On December 3, 2004, Bechtel filed an offer of judgment to settle its claims for a payment of $20 million by CYAPC, conditioned on CYAPC’s withdrawal of its counterclaim, which offer was rejected by CYAPC.  On February 22, 2005, CYAPC filed an offer of judgment to settle its counterclaims for a payment of $65 million by Bechtel, conditioned on Bechtel’s withdrawal of its claims.  Bechtel has 60 days to accept or reject the offer.  If the offers are rejected, and one of the parties subsequently wins the case in an amount equal to or greater than its offer, the court will add 12 percent annual interest on that award, computed from the date of the party’s claim, which is June 23, 2003 in the case of Bechtel’s claim, and August 22, 2003 in the case of CYAPC’s counterclaim.  

B.

FERC Proceeding

On July 1, 2004, CYAPC filed with the FERC to increase its decommissioning collections from $16.7 million per year (in 2000 dollars) to $93 million per year (in 2003 dollars) for the six-year period beginning January 1, 2005.  The 2003 estimate projects an increase of $395.6 million in 2003 dollars and a total cost to complete decommissioning of $831.3 million in 2003 dollars.  The increases largely reflect increased costs of security and insurance, the continuing cost of storing spent nuclear fuel that the DOE has failed to remove, the additional costs to CYAPC for it to manage the decommissioning activities that were Bechtel’s responsibilities and declining financial markets.

On August 30, 2004, the FERC issued an order accepting the CYAPC rate filing, suspending collections for five months and establishing hearing procedures.  Bechtel was allowed to intervene in the FERC case.  The FERC also denied the DPUC/OCC's petition for declaratory order, which had requested that the FERC determine that CYAPC's wholesale purchasers (its utility owners) were responsible for all decommissioning costs, including imprudent costs, but could only pass through to retail ratepayers prudent costs.  The FERC held that, under the Federal Power Act, its responsibility was to determine just and reasonable wholesale rates, and not determine retail rates.

On September 29, 2004, the DPUC/OCC sought rehearing of the FERC’s August 30 denial of their petition.  The rehearing again asks the FERC to enforce the CYAPC owners/purchasers’ obligation to pay all decommissioning costs, whether prudent or imprudent.  Bechtel also sought clarification of the August 30 order.

A schedule for the FERC trial on the reasonableness of the decommissioning rates has been set by the administrative law judge, with hearings commencing in June 2005 and an initial decision by September 30, 2005.  

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On October 29, 2004, the FERC issued an order granting for further consideration the requests of DPUC/OCC and Bechtel to rehear FERC’s denial of the declaratory petition.  The FERC did not set a date by which it would rule on the requests, and it is likely that an order won’t be issued until the conclusion of the case.  On November 22, 2004, CYAPC filed additional testimony to respond to DPUC/OCC’s claims that the Bechtel contract was imprudently managed.

On February 22, 2005, the DPUC and Bechtel each filed testimony with the FERC.  The DPUC argues that CYAPC’s imprudent management of the decommissioning project while Bechtel was the contractor resulted in schedule delays and cost increases, and recommends a disallowance in the range of about $225 to $234 million.  Bechtel claims that it was impossible for it to fulfill its contract obligations, that CYAPC was not justified in terminating its contract and that CYAPC’s approach to the remaining decommissioning work is faulty.

Discovery is ongoing and a trial has been tentatively scheduled for 2006.  Management cannot predict the outcome of this litigation or its impact on NU.

NU's electric operating subsidiaries collectively own 49.0 percent of CYAPC, as follows: CL&P - 34.5 percent, PSNH - 5.0 percent and WMECO - 9.5 percent.

10.

Enron Bankruptcy Claim

On March 31, 2004, CL&P was served with two state court complaints from CRRA (one suit is on behalf of CRRA, the other on behalf of the directors of CRRA) claiming that CL&P either negligently or fraudulently allowed CRRA and its directors to become involved with Enron (collectively, the CRRA Lawsuits).  Damages in excess of $200 million are claimed.  CL&P has answered the complaints denying all material allegations and is preparing a motion for summary judgment.   

On October 14, 2004, CRRA, the Connecticut Attorney General (AG) and CL&P entered into a Settlement Agreement, which resolves all open issues, claims and litigation between CRRA and CL&P arising out of the agreements entered into by the parties on or about December 22, 2000 (the December 22, 2000 Agreements), including the CRRA Lawsuits.  If the Settlement Agreement is approved by the Bankruptcy Court, it would also resolve all pending claims between CL&P and Enron arising out of the December 22, 2000 Agreements, except for CL&P’s pending claim against Enron Power Marketing Inc. (EPMI) for damages resulting from its rejection of the December 22, 2000 Electricity Purchase Agreement between EPMI and CL&P (rejection damages claim).  CL&P’s rejection damages claim currently seeks $42.9 million from EPMI.  

On December 1, 2004, the DPUC approved the Settlement Agreement, and OCC has waived (in writing) its right to appeal the DPUC's December 1 decision.  The settlement was approved by the Bankruptcy Court at a hearing on January 20, 2005 and no appeal was timely filed from the Bankruptcy Court’s January 20 decision.  Therefore, the settlement became effective on February 1, 2005 and CRRA withdrew with prejudice the remaining CRRA lawsuits on February 7, 2005.

11.

Northern Wood Power Project

In August 2003, PSNH sought the approval of the NHPUC to modify one of its older 50 MW coal-fired generating stations, Unit 5 at Schiller Station in Portsmouth (Northern Wood Power Project), to a technologically advanced fluidized bed boiler capable of burning wood, with the plan to burn locally sourced low-grade wood fuel.  This project would qualify Schiller Unit 5 to receive revenues from the sale of renewable energy certificates necessary to fulfill renewable portfolio standard requirements in Connecticut and Massachusetts.  In May 2004, the NHPUC approved the Northern Wood Power Project and a risk/reward cost-recovery mechanism jointly offered by PSNH, the New Hampshire Governor’s Office of Energy and Planning, the New Hampshire Office of Consumer Advocate, and the New Hampshire Timberland Owners’ Association.  The NHPUC’s orders approving this Northern Wood Power Project were appealed to the New Hampshire Supreme Court by four existing wood-fired generating plants located in that state.  In their December 2004 Supreme Court brief, the appellant wood-plants claim that there was not sufficient record evidence to demonstrate that the project is in the public interest of PSNH’s retail customers; that the NHPUC’s orders were administratively deficient; and, that the NHPUC was without authority to approve the risk/reward cost-recovery mechanism.  Reply briefs were filed by PSNH, the New Hampshire Attorney General’s Office and the Office of Consumer Advocate in January 2005.  The New Hampshire Supreme Court heard oral argument on February 16, 2005, and a decision is  expected by the end of April 2005.

12.

Connecticut MGP Cost Recovery

By letter dated August 5, 2004, Yankee Gas and CL&P (NU Companies) demanded contribution from UGI Utilities, Inc. (UGI) for past and future remediation costs related to MGP operations on thirteen sites currently or formerly owned by the NU Companies in a number of different locations throughout the State of Connecticut.  The NU Companies allege that UGI controlled operations of the plants at various times throughout the period 1883 to 1941.  According to the NU Companies’ demand letter, investigation and remedial costs at the sites to date total approximately $10 million and complete remediation costs for all sites could total $182 million.  The NU Companies

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are seeking a fair and equitable contribution for these costs from UGI.  UGI is reviewing the information provided by the NU Companies and is investigating the claim.

13.

Other Legal Proceedings

The following sections of Item 1, "Business" discuss additional legal proceedings: See “Risk Factors” for general information on several significant risks; "Regulated Electric Operations," and "Regulated Gas Operations" for information about various state restructuring and rate proceedings, civil lawsuits related thereto, the implementation of SMD,  and information about proceedings relating to power, transmission and pricing issues; "Competitive System Businesses" for information on issues relating to the operation of the merchant energy business, the provision of energy services and related matters; "Nuclear Activities" for information related to high-level and low-level radioactive waste disposal and decommissioning matters; and "Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality, toxic substances and hazardous waste, EMF, licensing of hydroelectric projects, and other matters.

Item 4.

Submission Of Matters To a Vote of Security Holders

No event that would be described in response to this item occurred with respect to NU, CL&P, PSNH or WMECO.

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Part II

Item 5.

Market for The Registrants' Common Equity and Related Stockholder Matters

NU.

The common shares of NU are listed on the New York Stock Exchange.  The ticker symbol is "NU," although it is frequently presented as "Noeast Util" and/or "NE Util" in various financial publications.  The high and low closing sales prices for the past two years, by quarters, are shown below.

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 stock during the fourth quarter of the year ended December 31, 2004.

As of January 31, 2005, there were 56,356 common shareholders of record of NU.  As of the same date, there were a total of 129,207,462 common shares issued, including 2,584,415 unallocated Employee Stock Ownership Plan (ESOP) shares held in the ESOP trust.

On January 31, 2005 the NU Board of Trustees approved the payment of a 16.25 cent per share dividend, payable on March 31, 2005, to shareholders of record as of March 1, 2005.

On January 12, 2004, the NU Board of Trustees approved the payment of a 15 cent per share dividend, payable on March 31, 2004, to shareholders of record as of March 1, 2004.

On April 13, 2004, the NU Board of Trustees approved the payment of a 15 cent per share dividend, payable on June 30, 2004, to shareholders of record as of June 1, 2004.

On May 10, 2004, the NU Board of Trustees approved the payment of a 16.25 cent per share dividend, payable on September 30, 2004, to shareholders of record as of September 1, 2004.

On October 12, 2004, the NU Board of Trustees approved the payment of a 16.25 cent per share dividend, payable on December 30, 2004, to shareholders of record as of December 1, 2004.

On January 13, 2003, the NU Board of Trustees approved the payment of a 13.75 cent per share dividend, payable on March 31, 2003, to shareholders of record as of March 1, 2003.

On April 8, 2003, the NU Board of Trustees approved the payment of a 13.75 cent per share dividend, payable on June 30, 2003, to shareholders of record as of June 1, 2003.

On May 13, 2003, the NU Board of Trustees approved the payment of a 15 cent per share dividend, payable on September 30, 2003, to shareholders of record as of September 1, 2003.

On October 14, 2003, the NU Board of Trustees approved the payment of a 15 cent per share dividend, payable on December, 2003, to shareholders of record as of December 1, 2003.

Information with respect to dividend restrictions for NU and its subsidiaries is contained in Item 1.  Business under the caption "Financing Program - Financing Limitations" and in Note A to the "Consolidated Statements of Shareholders' Equity" within NU's 2004 Annual Report to Shareholders, which information is incorporated herein by reference.

CL&P, PSNH and WMECO.  There is no established public trading market for the common stock of CL&P, PSNH and WMECO.  The common stock of CL&P, PSNH and WMECO is held solely by NU.

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During 2004 and 2003, CL&P approved and paid $47.1 million and $60.1 million of common stock dividends to NU.

During 2004 and 2003, PSNH approved and paid $27.2 million and $16.8 million of common stock dividends, respectively, to NU.

During 2004 and 2003, WMECO approved and paid approximately $6.5 million and $22 million of common stock dividends, respectively, to NU.

For information regarding securities authorized for issuance under equity compensation plans, see Item 12, "Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters," included in this report on Form 10-K.  

Item 6.

Selected Financial Data

NU.  Reference is made to information under the heading "Selected Consolidated Financial Data" contained within NU's 2004 Annual Report to Shareholders, which information is incorporated herein by reference.

CL&P.  Reference is made to information under the heading "Selected Consolidated Financial Data" contained within CL&P's 2004 Annual Report, which information is incorporated herein by reference.  

PSNH.  Reference is made to information under the heading "Selected Consolidated Financial Data" contained within PSNH's 2004 Annual Report, which information is incorporated herein by reference.

WMECO.  Reference is made to information under the heading "Selected Consolidated Financial Data" contained within WMECO's 2004 Annual Report, which information is incorporated herein by reference.

Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations

NU.  Reference is made to information under the heading "Management's Discussion and Analysis and Results of Operations" contained within NU's 2004 Annual Report to Shareholders, which information is incorporated herein by reference.

CL&P.  Reference is made to information under the heading "Management's Discussion and Analysis and Results of Operations" contained within CL&P's 2004 Annual Report, which information is incorporated herein by reference.

PSNH.  Reference is made to information under the heading "Management's Discussion and Analysis and Results of Operations" contained within PSNH's 2004 Annual Report, which information is incorporated herein by reference.

WMECO.  Reference is made to information under the heading "Management's Discussion and Analysis and Results of Operations" contained within WMECO's 2004 Annual Report, which information is incorporated herein by reference.

Item 7a. Quantitative and Qualitative Disclosures about Market Risk

Market Risk Information

Select Energy utilizes the sensitivity analysis methodology to disclose quantitative information for its commodity price risks.  Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from market risk-sensitive instruments over a selected time period due to one or more hypothetical changes in commodity prices, or other similar price changes.  Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity, contract prices and market prices represented by each derivative commodity contract.  For swaps, forward contracts and options, fair value reflects management's 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.

NU Enterprises - Wholesale and Retail Marketing Portfolio: When conducting sensitivity analyses of the change in the fair value of Select Energy's electricity, natural gas and oil on the wholesale and retail marketing portfolio, which would result from a hypothetical change in the future market price of electricity, natural gas and oil, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, natural gas and oil, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments. In most instances, market prices and volatility are determined from quoted prices on the futures exchange.

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Select Energy has determined a hypothetical change in the fair value for its wholesale and retail marketing portfolio, which includes cash flow hedges and electricity, natural gas and oil contracts, assuming a 10 percent change in forward market prices.  At December 31, 2004, a 10 percent change in market price would have resulted in an increase in fair value of $25.6 million or a decrease in fair value of $23.6 million.

The impact of a change in electricity, natural gas and oil prices on Select Energy's wholesale and retail marketing portfolio at December 31, 2004, is not necessarily representative of the results that will be realized when these contracts are physically delivered.

NU Enterprises - Trading Contracts:  At December 31, 2004, Select Energy has calculated the market price resulting from a 10 percent change in forward market prices.  That 10 percent change would result in approximately a $1.0 million increase or decrease in the fair value of the Select Energy trading portfolio.  In the normal course of business, Select Energy also faces risks that are either non-financial or non-quantifiable.  These risks principally include credit risk, which is not reflected in this sensitivity analysis

Other Risk Management Activities

Interest Rate Risk Management:  NU manages its interest rate risk exposure in accordance with its written policies and procedures by maintaining a mix of fixed and variable rate debt.  At December 31, 2004, approximately 86 percent (76 percent including the debt subject to the fixed-to-floating interest rate swap in variable rate debt) of NU’s long-term debt, including fees and interest due for spent nuclear fuel disposal costs, is at a fixed interest rate.  The remaining long-term debt is variable-rate and is subject to interest rate risk that could result in earnings volatility.  Assuming a one percentage point increase in NU’s variable interest rates, including the rate on debt subject to the fixed-to-floating interest rate swap, annual interest expense would have increased by $3.9 million.  At December 31, 2004, NU parent maintained a fixed-to-floating interest rate swap to manage the interest rate risk associated with its $263 million of fixed-rate debt.

Credit Risk Management:  Credit risk relates to the risk of loss that NU would incur as a result of non-performance by counterparties pursuant to the terms of its contractual obligations.  NU serves 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 NU realizes 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 which, in turn, requires NU to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by NU’s risk management process.

Credit risks and market risks at NU Enterprises are monitored regularly by a Risk Oversight Council operating outside of the business lines that create or actively manage these risk exposures to ensure compliance with NU’s stated risk management policies.  

NU tracks and re-balances the risk in its 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.

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.  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 December 31, 2004 and December 31, 2003, Select Energy maintained collateral balances from counterparties of $57.7 million and $46.5 million, respectively.  These amounts are included in both cash and cash equivalents and other current liabilities on the accompanying consolidated balance sheets.  Select Energy also has collateral balances deposited with counterparties of $46.3 million and $17 million at December 31, 2004 and December 31, 2003, respectively.

The Utility Group has a lower level of credit risk related to providing regulated electric and gas distribution service than NU Enterprises.  However, the Utility Group companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies.  The Utility Group manages the credit risk with these counterparties in accordance with established credit risk practices and maintains an oversight group that monitors contracting risks, including credit risk.

Additional quantitative and qualitative disclosures about market risk are set forth in "Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations," to the consolidated financial statements herein.

38

Item 8.

Financial Statements and Supplementary Data

NU.  Reference is made to information under the headings "Independent Auditors' Report," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Shareholders' Equity," "Consolidated Statements of Cash Flows," "Consolidated Statements of Capitalization," "Notes to Consolidated Financial Statements," and "Consolidated Statements of Quarterly Financial Data" contained within NU's 2004 Annual Report to Shareholders, which information is incorporated herein by reference.   

CL&P.  Reference is made to information under the headings "Independent Auditors' Report," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained within CL&P's 2004 Annual Report, which information is incorporated herein by reference.

PSNH.  Reference is made to information under the headings "Independent Auditors' Report," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained within PSNH's 2004 Annual Report, which information is incorporated herein by reference.

WMECO.  Reference is made to information under the headings "Independent Auditors' Report," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained within WMECO's 2004 Annual Report, which information is incorporated herein by reference.  

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

No events that would be described in response to this item have occurred with respect to NU, CL&P, PSNH or WMECO.

Item 9a.

Controls and Procedures

Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of NU and subsidiaries and of other sections of this annual report.  These financial statements, which were audited by Deloitte & Touche LLP, have been prepared in conformity with accounting principles generally accepted in the United States of America using estimates and judgments, where required, and giving consideration to materiality.

Additionally, management is responsible for establishing and maintaining adequate internal controls over financial reporting.  Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, NU conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, management concluded that our internal controls over financial reporting was ineffective as of December 31, 2004.  Management identified a material weakness due to deficiencies in both the design and operating effectiveness of internal controls associated with the application of derivative accounting rules to certain wholesale natural gas contracts entered into by the wholesale marketing portion of NU Enterprises’ merchant energy segment.  NU filed a Form 8-K on January 26, 2005 to provide notice of the restatement of June 30, 2004 and September 30, 2004 reports on Form 10-Q due to this accounting error.  Restatements amounted to an increase in net income of $1.1 million for the quarter ended June 30, 2004 and a decrease in net income of $47 million for the quarter ended September 30, 2004.  Numerous account balances were affected by these material misstatements, primarily fuel, purchased and net interchange power, income tax expense, derivative assets, derivative liabilities, retained earnings, and accumulated other comprehensive income.  

Accounting for derivative contracts is complex and requires a significant amount of judgment and interpretation of the rules.  During the second and third quarters of 2004, management accounted for certain wholesale natural gas contracts using the accrual method of accounting.  Using this method, changes in the fair value of the derivative contracts did not impact net income currently.  As a result of further analysis performed through January 2005, management concluded that an error had been made in interpreting the derivative accounting rules.  This misinterpretation led to a misapplication of the derivative accounting rules.  These wholesale natural gas contracts should have been recorded at fair value with changes in fair value reflected currently in net income.  The restatements discussed above were required in order to apply fair value accounting to these contracts.  The material weakness occurred due to deficiencies in both the design and operating effectiveness of the internal control environment.

Management identified and is strengthening the effectiveness and design of internal controls related to this matter.  During the first quarter of 2005, management is enhancing the effectiveness of internal controls by requiring additional documentation for each wholesale derivative transaction accounted for on an accrual basis.  Management is also enhancing the design of internal controls as follows.  Accounting

39

management will review and approve the accounting for all material transactions requiring accounting judgments.  Accounting reporting relationships will be enhanced by having business unit controllers report to the corporate controller for accounting and financial reporting matters.

These control enhancements are being implemented in the first quarter of 2005.  As a result, material misstatements in account balances and related disclosures associated with this material weakness are not expected in the future.  However, until these controls or control enhancements are concluded to be operating effectively, management cannot determine if the material weakness described above will be eliminated.

This material weakness was discussed with the Audit Committee of the Board of Trustees and Deloitte & Touche LLP, our independent registered public accounting firm.  Deloitte & Touche LLP, has issued an attestation report on management’s assessment of internal controls over financial reporting.

NU undertook, in a separate evaluation, of the design and operation of their disclosure controls and procedures to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Exchange Act and the rules and forms of the SEC.  This evaluation was made under the supervision and with the participation of management, including NU’s principal executive officer and principal financial officer, as of the end of the period covered by this Annual Report on Form 10-K.  The principal executive officer and principal financial officer have concluded, based on their review, that NU’s disclosure controls and procedures are ineffective, solely related to the material weakness described above,  to ensure that information required to be disclosed by the companies in reports that it files under the Exchange Act i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms and ii) is accumulated and communicated to management including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

The principal executive officer and principal financial officer of CL&P, PSNH, and WMECO believe that their disclosure controls and procedures are effective to ensure that information required to be disclosed by CL&P, PSNH, and WMECO in reports that they file under the Exchange Act i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms and ii) is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

There have been no significant changes in internal controls over financial reporting during the quarter ended December 31, 2004 that have materially affected, or are reasonably likely to materially affect internal controls over financial reporting.

Item 9b.

Other Information

No information is required to be disclosed under Item 9b at December 31, 2004, as this information has been previously disclosed in applicable reports on Form 8-K during the fourth quarter of 2004.

40

PART III

Item 10.

Directors and Executive Officers of The Registrants

The information in Item 10 is provided as of March 1, 2005 except where otherwise indicated.

NU.

In addition to the information provided below concerning the executive officers of NU, incorporated herein by reference is the information contained in the sections "Proxy Statement - Election of Trustees," "Board Committees and Responsibilities," "Selection of Trustees," and "Section 16(a) Beneficial Ownership Reporting Compliance," of the definitive proxy statement for solicitation of proxies by NU’s Board of Trustees, to be dated March 31, 2005, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

         Name          

Positions  Held 

Gregory B. Butler (1)

SVP, SEC, GC

Lawrence E. De Simone (2)

P

John H. Forsgren (3)

EVP, CFO, VC, T

Cheryl W. Grisé (1)

P

David R. McHale  (4)

SVP, CFO

Leon J. Olivier (5)

P

Charles W. Shivery (1)

CHB, P, CEO, T

CL&P

         Name          

Positions  Held 

David H. Boguslawski (7)

D, VP

Gregory B. Butler (1)

OTH

John H. Forsgren (3)

EVP, CFO

Cheryl W. Grisé (1)

CEO, D

David R. McHale (4)

SVP, CFO

Raymond P. Necci (6)

P, COO, D

Leon J. Olivier (5)

OTH, D

Charles W. Shivery (1)

OTH

PSNH

         Name          

Positions  Held 

David H. Boguslawski (7)

D, VP

Gregory B. Butler (1)

OTH

John H. Forsgren (3)

EVP, CFO, D

Cheryl W. Grisé (1)

CEO, D

Gary A. Long (1)

P, COO, D

David R. McHale (4)

SVP, CFO, D

Leon J. Olivier (5)

OTH, D

Charles W. Shivery (1)

OTH

41

WMECO.

        Name          

Positions  Held 

David H. Boguslawski (7)

D, VP

Gregory B. Butler (1)

OTH

John H. Forsgren (3)

EVP, CFO, D

Cheryl W. Grisé (1)

CEO, D

Kerry J. Kuhlman (8)

P, D

David R. McHale (4)

SVP, CFO, D

Leon J. Olivier (5)

OTH, D

Rodney O. Powell (1)

P, COO, D

Charles W. Shivery (1)

OTH

(1)

Executive Officer.

(2)

Became an executive officer of NU upon election as President-Competitive Group effective October 25, 2004.

(3)

Retired as of the end of 2004.

(4)

Became an executive officer upon election as Senior Vice President and Chief Financial Officer effective January 1, 2005.

(5)

Became an executive officer upon election as President-Transmission Group of NU effective January 17, 2005.  Elected Director of WMECO & PSNH on January 17, 2005.  

(6)

Became an executive officer of CL&P upon election as President and Chief Operating Officer, effective January 17, 2005.  Also elected a Director of CL&P, effective January 17, 2005.

(7)

Resigned as Director, effective January 16, 2005.

(8)

President and Director through December 31, 2004.  

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          Name          

Age

Business Experience During Past 5 Years

David H. Boguslawski

50

Vice President – Transmission Strategy and Operations since January 17, 2005; previously Vice President - Transmission Business of CL&P, PSNH and WMECO from May 1, 2001 to January 16, 2005 and a Director of CL&P, PSNH and WMECO from June 30, 1999 to January 16, 2005; previously Vice President - Energy Delivery of CL&P, PSNH and WMECO from September 1996 to May 2001.

Gregory B. Butler

47

Senior Vice President, Secretary and General Counsel of NU since August 31, 2003 and a Director of Northeast Utilities Foundation, Inc. since December 1, 2002; previously Vice President, Secretary and General Counsel of NU from May 1, 2001 through August 30, 2003; Vice President - Governmental Affairs of NUSCO from January 1997 to May 2001.

Lawrence E. De Simone

57

President-Competitive Group of NU and President of NU Enterprises, Inc., since October 25, 2004 and President of Select Energy, Inc, since February 1, 2005; previously Executive Vice President - Regulated Business and Services of PPL Corporation from January 1, 2004 to August 31, 2004; Executive Vice President - Supply of PPL Corporation from October 2001 to December 31, 2003; and President of PPL EnergyPlus from November 1, 1998 to September 30, 2001.

John H. Forsgren (*)

58

Retired as of the end of 2004; previously Vice Chairman of NU from May 1, 2001 to December 31, 2004; Executive Vice President and Chief Financial Officer of NU from February 1, 1996 to December 31, 2004; Executive Vice President and Chief Financial Officer of CL&P, PSNH, and WMECO from February 27, 2003 to December 31, 2004 and from February 1996 to June 1999; Director of WMECO from June 10, 1996 to December 31, 2004 and of PSNH from August 5, 1996 to December 31, 2004 and a Director of Northeast Utilities Foundation, Inc. from September 23, 1998 to December 31, 2004;  Director of CL&P from June 1996 to June 1999.  

Cheryl W. Grisé (**)

52

President – Utility Group of NU since May 2001, Chief Executive Officer of CL&P, PSNH and WMECO since September 10, 2002, a Director of CL&P since May 1, 2001, PSNH since May 14, 2001 and WMECO since June 2001, and a Director of Northeast Utilities Foundation, Inc. since September 23, 1998; previously President of CL&P from May 2001 to September 2001, Senior Vice President, Secretary and General Counsel of NU from July 1998 to May 2001, Senior Vice President, Secretary and General Counsel of CL&P and PSNH and Senior Vice President, Secretary, Assistant Clerk and General Counsel of WMECO from July 1998 to June 1999 and Senior Vice President, Secretary and General Counsel of NGC from January 1999 to June 1999; previously Director of CL&P and WMECO (January 1994 through November 1997) and PSNH  (February 1995 through November 1997); Senior Vice President and Chief Administrative Officer of CL&P and PSNH, and Senior Vice President of WMECO from 1995 to 1998.

Kerry J. Kuhlman

54

President and Chief Operating Officer and a Director of WMECO from April 1999 through December 31, 2004; previously Vice President-Customer Operations of WMECO from October 1998 to April 1999; Vice President-Central Region of CL&P from August 1997 to October 1998; and Vice President-Eastern Region of CL&P from July 1994 to August 1997.

Gary A. Long (***)

53

President and Chief Operating Officer and a Director of PSNH since July 1, 2000; previously Senior Vice President - PSNH of PSNH from February 2000 through June 2000 and Vice President - Customer Service and Economic Development of PSNH from January 1994 to February 2000.

David R. McHale

44

Senior Vice President and Chief Financial Officer of NU, CL&P, WMECO and PSNH since January 1, 2005 and a Director of WMECO and PSNH since January 1, 2005; previously Vice President and Treasurer of NU, WMECO and PSNH since July 1998.

43

Raymond P. Necci

53

President and Chief Operating Officer and a Director of CL&P since January 1, 2005.  Previously Vice President - Utility Group Services of NUSCO from January 1, 2002 to January 16, 2005; Vice President - Nuclear Operations of Dominion Nuclear Connecticut from March 31, 2001 to December 31, 2001; and Vice President - Nuclear Technical Services of Northeast Nuclear Energy Company from December 15, 1999 to March 31, 2001.

Leon J. Olivier

56

President - Transmission Group of NU and a Director of WMECO and PSNH since January 17, 2005 and a Director of CL&P since September 2001.  Previously, President and Chief Operating Officer of CL&P from September 2001 to January 2005; previously Senior Vice President of Entergy Nuclear Corp. from April 2001 to September 2001; Senior Vice President and Chief Nuclear Officer of Northeast Nuclear Energy Company from October 1998 to May 2001.

Rodney O. Powell

52

President and a Director of WMECO since January 1, 2005.  Previously Vice President - Customer Relations of CL&P from January 1, 2002 to December 31, 2004; Vice President - Central Region of CL&P from October 14, 1998 to January 1, 2002; and a Director of CL&P from June 30, 1999 to September 10, 2001.

Charles W. Shivery (****)

59

Chairman of the Board, President and Chief Executive Officer of NU since March 29, 2004; Previously, President (interim) of NU from January 1, 2004 to March 29, 2004 and a Director of Northeast Utilities Foundation since March 3, 2004; previously President - Competitive Group of NU and President and Chief Executive Officer of NU Enterprises, Inc., from June 2002 through December 31, 2003; Co-President of Constellation Energy Group, Inc. from October 2000 to February 2002; President and Chief Executive Officer of Constellation Power Source Holdings, Inc., from July 2000 to February 2002; Chief Executive Officer and President of Constellation Enterprises, Inc. from 1998 to February 2002; and Chairman of the Board, President and Chief Executive Officer of Constellation Power Source, Inc., from 1997 to February 2002.  

 (*)

Mr. Forsgren is a Director of NEON Communications, Inc. and CuraGen Corporation.

 (**)

Mrs. Grisé is a Director of MetLife, Inc. and Dana Corporation.

 (***)

Mr. Long is a Director of Citizens Bank-NH.

 (****)

Mr. Shivery is a Director of Energy Insurance Mutual, the Connecticut Business & Industry Association and Connecticut Children’s Hospital.

There are no family relationships between any director or executive officer and any other director or executive officer of NU, CL&P, PSNH or WMECO.

NU, CL&P, PSNH, WMECO

Each of the registrants has adopted a Code of Ethics for Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller).  The Code of Ethics has been posted on Northeast Utilities’ web site and is available at http://www.nu.com/investors/corporate_gov/default.asp on the Internet.  Information pertaining to amendments and waivers from the Code of Ethics will be posted at this site.

Printed copies of the Code of Ethics are also available to any shareholder without charge upon written request mailed to:

Mr. Gregory B. Butler, Senior Vice President,

Secretary and General Counsel

Northeast Utilities Service Company

P.O. Box 270

Hartford, CT  06414

44

Item 11.

Executive Compensation

NU

Incorporated herein by reference is the information contained in the sections "Executive Compensation," "Long-Term Incentive Plans -Awards in Last Fiscal Year," "Pension Benefits," "Trustee Compensation," "Employment Contracts and Termination of Employment and Change in Control Arrangements," "Compensation Committee Report on Executive Compensation" and "Share Performance Chart" of the definitive proxy statement for solicitation of proxies by NU’s Board of Trustees, to be dated March 31, 2005, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

CL&P, PSNH, WMECO

SUMMARY COMPENSATION TABLE

The following tables present the cash and non-cash compensation received by the Chief Executive Officer and the next four highest paid executive officers of CL&P, PSNH, and WMECO in accordance with rules of the Securities and Exchange Commission (SEC):

45

Notes:

(1)

"Other Annual Compensation" for Mr. Shivery includes $144,000 of relocation expenses in 2002, per his employment agreement.  "Other Annual Compensation" for Mr. Olivier includes $105,966 of supplemental pension payments payable under his previous employment agreement with Northeast Nuclear Energy Company, an affiliate of CL&P.  "Other Annual Compensation" for other officers includes miscellaneous items such as reimbursement for financial planning fees.

(2)

Restricted shares listed in the Table are valued as of the date of grant.  The aggregate restricted share holdings by the individuals named in the table were, at December 31, 2004, 252,761 common shares, with an aggregate value of $4,764,545.  The aggregate restricted share holdings by each of the individuals named in the table and the value thereof, at December 31, 2004, were 67,667 common shares ($1,275,711) for Mr. Shivery; 81,495 common shares ($1,536,181) for Mr. Forsgren; 61,926 common shares ($1,167,305) for Mrs. Grisé 19,289 common shares ($363,598) for Mr. Butler; 8,560 common shares ($161,356) for Mr. Olivier; 7,027 common shares ($132,459) for Mr. Long and 6,797 common shares ($128,123) for Mrs. Kuhlman.  Each of the individuals were awarded restricted share units as long term incentive compensation during 2004, which vest over four years, with 50% payable at vesting and 50% payable 4 years after vesting;  dividends on restricted share units are reinvested and additional shares added as a result of reinvestment are vested and paid on the same schedule. In addition, Mr. Shivery was awarded 25,000 restricted shares in 2004 upon his appointment as Chairman, President and CEO; these shares vest over 4 years and dividends are paid out during the vesting period.  In 2003, certain individuals were awarded restricted shares as long term compensation which vest over four years; dividends on these restricted shares are paid out during the vesting period. Payment of 50% of the 2003 annual incentive payout for Mr. Shivery, Mr. Forsgren and Mrs. Grisé was made in restricted share units which vest over three years and on which dividends are reinvested during the vesting period.  Payment of 50 percent of the 2001 and 2002 annual bonuses of each of Mr. Forsgren and Mrs. Grisé was made on February 25, 2002 and February 25, 2003, respectively, in the form of restricted shares vesting one-third on each of the next three anniversaries of these payments; dividends on these restricted shares granted in 2003 are paid out during the vesting period.

(3)

"All Other Compensation" for 2004 consists of employer matching contributions under the Northeast Utilities Service Company 401k Plan, generally available to all eligible employees ($6,150 for each named officer other than Mr. Forsgren - $0, Mr. Long - $5,792 and Mrs. Kuhlman - $5,610), matching contributions under the Deferred Compensation Plan for Executives (Mr. Shivery - $17,831, Mrs. Grisé - $9,016, Mr. Butler - $2,988 and Mr. Olivier - $3,771) and dividends on restricted stock (Mr. Shivery - $19,169, Mr. Forsgren - $14,172, Mrs. Grisé - $10,774, Mr. Butler - $3,647, Mr. Olivier - $2,603. Mr. Long - $2,155 and Mrs. Kuhlman - $2,072).  For Mr. Forsgren and Mrs. Grisé, it also includes vested deferred compensation paid out in 2004 of $200,112 and $203,381, respectively (See Employment Contracts and Termination of Employment and Change in Control Arrangements, below).

(4)

Retired December 31, 2004.

(5)

Served as interim President effective January 1, 2004 and elected Chairman of the Board, President and Chief Executive Officer on March 29, 2004.

(6)

Mr. Olivier served as President of CL&P through January 17, 2005.

(7)

Mrs. Kuhlman served as President of WMECO through December 31, 2004.

46

LONG-TERM INCENTIVE PLANS – AWARDS IN LAST FISCAL YEAR

Grants of three-year performance units were made during 2004 under the Northeast Utilities Incentive Plan to the Company’s officers.  Payments will be made in cash following the close of the performance period.  Threshold, target, and maximum payouts will be determined based on net income over the performance period.  In the event of termination due to retirement, death, or disability, grants are prorated based on time in the performance period and their value shall be determined based on performance through the end of the performance period.  In the event of a Change of Control, as defined, grants are prorated based on time in the performance period, their value shall be set at target, and their value shall be paid immediately.  In the event of a Termination Upon a Change of Control, as defined, grants are fully vested, their value shall be set at target, and their value shall be paid immediately.  Grants to the executive officers named in the Summary Compensation Table were as follows:

PENSION BENEFITS

The tables on the following pages show the estimated annual retirement benefits payable to an executive officer of CL&P, PSNH or WMECO upon retirement, assuming that retirement occurs at age 65 and that the officer is at that time not only eligible for a pension benefit under the Northeast Utilities Service Company Retirement Plan (the Retirement Plan) but also eligible for either the make-whole benefit or the make-whole benefit plus the target benefit under the Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies (the Supplemental Plan).  The Supplemental Plan is a non-qualified pension plan providing supplemental retirement income to system officers.  The make-whole benefit under the Supplemental Plan, available to all officers, makes up for benefits lost through application of certain tax code limitations on the benefits that may be provided under the Retirement Plan, and includes as "compensation" awards under the executive incentive plans and deferred compensation (as earned).  The target benefit further supplements these benefits and is available to officers at the Senior Vice President level and higher who are selected by the Board of Trustees to participate in the target benefit and who remain in the employ of Northeast Utilities companies until at least age 60 (unless the Board of Trustees sets an earlier age).

Messrs. Shivery and Butler and Mrs. Grisé are currently eligible for a make-whole plus a target benefit and Mr. Forsgren, having retired at the end of 2004, is currently receiving such benefit. Messrs. Olivier and Long and Mrs. Kuhlman are eligible for the make-whole benefit but not the target benefit.

Mr. Shivery’s employment agreement provides for a special retirement benefit, following completion of five years of service with the Company (2007), consisting of the excess over benefits otherwise payable from the Retirement Plan and the Supplemental Plan needed to give him the equivalent of fully-vested benefits under the Retirement Plan and the Supplemental Plan calculated by adding three additional years to his actual service and utilizing an early commencement reduction factor of 2 percent per year for each year younger than age 65 at commencement, if better than the factors then in use under the Retirement Plan.

Mr. Forsgren’s employment agreement provides for supplemental pension benefits based on crediting additional service for the make-whole plus target benefit under the Supplemental Plan. Based on his age and service at retirement, Mr. Forsgren is eligible for a make-whole plus target benefit based on crediting 11.9 extra years of service, unreduced for early commencement.  Mr. Forsgren’s employment agreement also provides for payments equal to 25 percent of final average compensation (not to exceed 170 percent of highest average base compensation received in any 36 month period) for up to 15 years following retirement, reduced by four percentage points for each year that his age is less than 65 years at retirement.  Because Mr. Forsgren retired at the end of 2004 at the age of 58 years and 4 months, the amount of supplemental 15-year annuity benefit provided will equal 18.3% of his final average compensation, which includes an average incentive of 70% of base pay.  Also, as a result of his retirement, Mr. Forsgren’s 2003 restricted shares issued under the Long-Term Incentive Program were vested on a pro rata basis, so that 6,398 restricted shares with a value of $120,602 as of December 31, 2004, became immediately vested.

47

The terms of Mr. Olivier’s employment provide for certain supplemental pension benefits in lieu of a make-whole benefit if certain eligibility requirements are met, in order to provide a benefit similar to that provided by his previous employer.  If Mr. Olivier remains in continuous employment with the Company until September 10, 2011 (or earlier with the Company’s permission), he will be eligible for a special benefit, subject to reduction for termination prior to age 65, of three percent of Final Average Compensation for each of his first 15 years of service since September 10, 2001 plus one percent of Final Average Compensation for each of the second 15 years of service.  Alternatively, if he does not voluntarily terminate his employment with the Company prior to his 60th birthday, or upon earlier termination upon a Change of Control, as defined in the Special Severance Program, he may receive upon retirement a lump sum payment of $2,050,000 in lieu of the make-whole benefit and the benefit described in the preceding sentence.  These supplemental pension benefits will be offset by the value of any benefits he receives from the Retirement Plan.

ANNUAL BENEFIT FOR OFFICERS ELIGIBLE FOR MAKE-WHOLE BENEFIT

ANNUAL BENEFIT FOR OFFICERS ELIGIBLE  FOR

 TARGET PLUS MAKE WHOLE BENEFIT

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The benefits presented in the tables above are based on a straight life annuity beginning at age 65 and do not take into account any reduction for joint and survivorship annuity payments.  Final average compensation for purposes of calculating the target benefit is the highest average annual compensation of the participant during any 36 consecutive months compensation was earned.  Final average compensation for purposes of calculating the make-whole benefit is the highest average annual compensation of the participant during any 60 consecutive months compensation was earned.  Compensation for these benefits includes the annual salary and bonus shown in the Summary Compensation Table and, for the make-whole benefit for officers hired before November 1, 2001, and for the target benefit for officers who were hired before November 1, 2001 and eligible for the target benefit prior to October 2003, an amount that represents the annual value of long-term incentive compensation.  Compensation for purposes of these benefits does not include employer matching contributions under the 401k Plan.  In the event that an officer's employment terminates because of disability, the retirement benefits shown above would be offset by the amount of any disability benefits payable to the recipient that are attributable to contributions made by Northeast Utilities and its subsidiaries under long-term disability plans and policies.

The compensation covered by the Supplemental Plan in 2004 for Mr. Shivery, Mr. Forsgren, Mrs. Grisé, Mr. Butler, Mr. Olivier, Mr. Long, and Mrs. Kuhlman was $999,380, $861,803, $877,038, $379,931, $516,741, $295,236 and $274,097, respectively.

As of December 31, 2004, the executive officers named in the Summary Compensation Table had attained the following years of credited service for purposes of the Supplemental Plan: Mr. Shivery – 2, Mr. Forsgren – 8, Mrs. Grisé – 24, Mr. Butler - 8, Mr. Olivier - 5, Mr. Long - 29, and Mrs. Kuhlman - 23.  Mr. Forsgren had 20 years of service for purposes of his supplemental pension benefit.  

EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT ARRANGEMENTS

NUSCO has entered into employment agreements or arrangements with Messrs. Shivery, Butler, Forsgren and Olivier and Mrs. Grisé Mr. Olivier and each of the other named executive officers participate in the Special Severance Program for Officers of Northeast Utilities System Companies.  The agreements and the Special Severance Program are also binding on Northeast Utilities and, except for Mr. Shivery’s agreement, on certain majority-owned subsidiaries of Northeast Utilities.  

The agreements with Messrs. Shivery, Forsgren and Butler and Mrs. Grisé obligate the officer to perform such duties as may be directed by the NUSCO Board of Directors or the Northeast Utilities Board of Trustees, protect the Company’s confidential information, refrain, while employed by the Company and for a period of time thereafter, from competing with the Company in a specified geographic area, and provide that the officer’s base salary will not be reduced below certain levels without the consent of the officer.  These agreements also provide that the officer will participate in specified benefits under the Supplemental Executive Retirement Plan or other supplemental retirement programs (see Pension Benefits, above) and/or in certain executive incentive programs at specified incentive opportunity levels, for a specified employment term and for automatic one-year extensions of the employment term unless at least six months’ notice of non-renewal is given by either party.  The employment term may also be ended by the Company for "cause," as defined, at any time (in which case no supplemental retirement benefit, if any, shall be due), or by the officer on thirty days’ prior written notice for any reason.  Absent "cause," the Company may remove the officer from his or her position on sixty days’ prior written notice, but in the event the officer is so removed and signs a release of all claims against the Company, the officer will receive two years’ base salary and annual incentive payments, specified employee welfare and pension benefits, and vesting of specified long-term incentive compensation.  

Under the terms of these agreements and the Special Severance Program, upon any termination of employment following a change of control, as defined, between (a) the earlier of the date shareholders approve a change of control transaction or a change of control transaction occurs and (b) the earlier of the date, if any, on which the Board of Trustees abandons the transaction or the date two years following the change of control, if the officer signs a release of all claims against the Company, the officer will be entitled to certain payments including a multiple (not to exceed three) of annual base salary, annual incentive payments, specified employee welfare and pension benefits, and vesting of stock appreciation rights, options and restricted stock.  Certain of the change of control provisions may be modified by the Board of Trustees prior to a change of control, on at least two years’ notice to the affected officer(s).  

Besides the terms described above, Mr. Shivery’s employment agreement provides for a specified initial salary, cash, and stock options upon employment, a special incentive program and special retirement benefits, and Mr. Forsgren’s employment agreement provides for special retirement benefits.  See Pension Benefits, above, for further description of these provisions.  The agreements of Mr. Forsgren and Mrs. Grisé were supplemented during 2001 to provide for special deferred compensation of $520,000 and $500,000, respectively, which payments were vested and paid in even installments (adjusted to reflect investment performance) on June 28, 2002, 2003 and 2004.

A letter agreement reflecting the terms of employment of Mr. Olivier provide for specified initial salary, restricted shares, and stock options, retirement and other benefits upon employment.

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The descriptions of the various agreements set forth above are for purpose of disclosure in accordance with the proxy and other disclosure rules of the SEC and shall not be controlling on any party; the actual terms of the agreements themselves determine the rights and obligations of the parties.

Item 12.

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

NU.

Incorporated herein by reference is the information contained in the sections "Common Stock Ownership of Certain Beneficial Owners," "Common Stock Ownership of Management," and "Securities Authorized for Issuance Under Equity Compensation Plans" of the definitive proxy statement for solicitation of proxies by NU’s Board of Trustees, to be dated March 31, 2005, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

CL&P, PSNH, and WMECO.  

NU owns 100% of the outstanding common stock of registrants CL&P, PSNH, and WMECO.  The following table sets forth, as of March 1, 2005, (except for Mr. Forsgren’s beneficial ownership, which is given as of December 31, 2004, his last day as an Executive Officer of these companies) the beneficial ownership of the equity securities of NU by (i) the Chief Executive Officer of each of CL&P, PSNH and WMECO and the Executive Officers of CL&P, PSNH, and WMECO listed on the Summary Compensation Table in Item 11 and (ii) all of the current Executive Officers and directors of each of CL&P, PSNH and WMECO, as a group.  No equity securities of CL&P, PSNH, or WMECO are owned by the Directors and Executive Officers of CL&P, PSNH, and WMECO.  Unless otherwise noted, each Director and Executive Officer of CL&P, PSNH, and WMECO has sole voting and investment power with respect to the listed shares.

Amount beneficially owned by Directors and Executive Officers as a group:

Notes:

 (1)

Includes 29,800 shares that could be acquired by Mr. Butler pursuant to currently exercisable options and 3,890 shares as to which Mr. Butler has sole voting and no dispositive power.

 (2)

As of March 1, 2004, the Directors and Executive Officers of CL&P, PSNH, or WMECO individually and as a group, owned less than one percent of the shares outstanding.

 (3)

Includes 134,266 shares that could have been acquired by Mr. Forsgren as of December 31, 2004 pursuant to then currently exercisable options and 28,343 shares as of December 31, 2004 as to which Mr. Forsgren had sole voting and no dispositive power.

(4)

Includes 171,228 shares that could be acquired by Mrs. Grisé pursuant to currently exercisable options and 14,779 shares as to which  Mrs. Grisé has sole voting and no dispositive power, and 265 shares held by Mrs. Grisé’s husband as custodian for her children, with whom she shares voting and dispositive power.

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(5)

Includes 28,864 shares that could be acquired by Mrs. Kuhlman pursuant to currently exercisable options and 2,210 shares as to which Mrs. Kuhlman has sole voting and no dispositive power.

(6)

Includes 28,050 shares that could be acquired by Mr. Long pursuant to currently exercisable options and 2,299 shares as to which Mr. Long has sole voting and no dispositive power.  

(7)

Includes 19,900 shares that could be acquired by Mr. Olivier pursuant to currently exercisable options and 2,776 shares as to which Mr. Olivier has sole voting and no dispositive power.  

(8)

Includes 19,349 shares that could be acquired by Mr. Shivery pursuant to currently exercisable options and 26,530 shares as to which Mr. Shivery has sole voting and no dispositive power.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The following table sets forth the number of Common Shares of Northeast Utilities issuable under the equity compensation plans of the Northeast Utilities System, as well as their weighted exercise price, in accordance with the rules of the Securities and Exchange Commission:

Notes to table:

1.

Under the Northeast Utilities Incentive Plan, 6,301,994 shares were available for issuance as of December 31, 2004.  In addition, an amount equal to one percent of the outstanding shares as of the end of each year becomes available for issuance under the Incentive Plan the following year.  Under the Northeast Utilities Employee Share Purchase Plan II, 6,723,969 additional shares are available for issuance.  Each such plan expires in 2008.

Item 13.

Certain Relationships and Related Transactions

Incorporated herein by reference is the information contained in the section "Certain Relationships and Related Transactions" of the definitive proxy statement for solicitation of proxies by NU’s Board of Trustees, to be dated March 31, 2005, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

Item 14.

Principal Accountant Fees and Services

NU

Incorporated herein by reference is the information contained in the sections "Pre-Approval of Services Provided by Principal Auditors" and "Fees Paid to Principal Auditor" of the definitive proxy statement for solicitation of proxies by NU’s Board of Trustees, to be dated March 31, 2005, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

CL&P, WMECO, PSNH

None of CL&P, WMECO and PSNH are subject to the audit committee requirements of the Securities and Exchange Commission, the national securities exchanges or the national securities associations.  CL&P, WMECO and PSNH obtain audit services from the independent auditor engaged by the Audit Committee of NU’s Board of Trustees.  The NU Audit Committee has established policies and procedures regarding the pre-approval of services provided by the principal auditors. Those policies and procedures delegate pre-approval

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of services to the NU Audit Committee Chair and/or Vice Chair provided that such offices are held by NU Trustees who are "independent" within the meaning of the Sarbanes-Oxley Act of 2002 (SOX) and that all such pre-approvals are presented to the Audit Committee at the next regularly scheduled meeting of the Committee.  The following relates to fees and services for the entire Northeast Utilities System, including CL&P, WMECO, and PSNH: 

Fees Paid to Principal Auditor

The Company’s principal auditor was paid fees aggregating $2,930,455 and $ 1,735,113 for the years ended December 31, 2004 and 2003, respectively, comprised of the following:

1.

Audit Fees

The aggregate fees billed to NU and its subsidiaries by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, the "Deloitte Entities") for audit services rendered for the years ended December 31, 2004 and 2003 totaled $2,679,300 and $1,441,700, respectively. The audit fees were incurred for audits of the annual consolidated financial statements of NU and its subsidiaries, reviews of financial statements included in quarterly reports on Form 10-Q of NU and its subsidiaries, comfort letters, consents and other costs related to registration statements and financings. The 2004 fees also included an audit of internal controls over financial reporting as of December 31, 2004.  

2

Audit Related Fees

The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for audit related services rendered for the years ended December 31, 2004 and 2003 totaled $174,950 and $150,200, respectively, primarily related to the examination of management’s assertions of CL&P’s, PSNH’s and WMECO’s securitization subsidiaries and the Company’s 401k Plan.

3.

Tax Fees

The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for tax services for the years ended December 31, 2004 and 2003 totaled $54,965 and $47,500, respectively. These services related solely to reviews of tax returns. There were no services related to tax advice or tax planning.

4.

All Other Fees

The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for the years ended December 31, 2004 and 2003 for services other than the services described above totaled $21,240 and $95,713, respectively, primarily related to tax return software licensing and training classes provided by the Deloitte Entities.  Included in 2003 "all other fees" are $16,620 (1% of total fees) of services where pre-approval was not required, as such services were de minimis.

The NU Audit Committee has considered whether the provision by the Deloitte Entities of the non-audit services described above was allowed under Rule 2-01(c)(4) of Regulation S-X and was compatible with maintaining auditor independence and has concluded that the Deloitte Entities were and are independent of the Company in all respects.

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Part IV

Item 15.

Exhibits and Financial Statement Schedules

(a)

1.

Financial Statements:

The Reports the of Independent Registered Public Accounting Firm and financial statements of CL&P, PSNH and WMECO are hereby incorporated by reference and made a part of this report (see "Item 8. Financial Statements and Supplementary Data").

Report of Independent Registered Public Accounting Firm

S-1

2.

Schedules:

Financial Statement Schedules for NU (Parent), NU and Subsidiaries, CL&P

and Subsidiaries, PSNH and Subsidiaries, and WMECO and Subsidiary

are listed in the Index to Financial Statements Schedules

S-2

3.

Exhibits Index

E-1

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NORTHEAST UTILITIES

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

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THE CONNECTICUT LIGHT AND POWER COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

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WESTERN MASSACHUSETTS ELECTRIC COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.