CONNECTICUT LIGHT & POWER CO - Annual Report: 2005 (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 if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) 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.

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SEC staff has granted Northeast Utilities a waiver from this requirement on November 1, 2005 with respect to its S-3 registration statement.

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 registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.  (Check one):

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

The aggregate market value of Northeast Utilities' Common Shares, $5.00 Par Value, held by non-affiliates, 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, 2005) was $2,705,441,684 based on a closing sales price of $20.86 per share for the 129,695,191 common shares outstanding on June 30, 2005.  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.

Indicate the number of shares outstanding of each of the registrants' classes of common stock, as of the latest practicable date:

Documents Incorporated by Reference:

GLOSSARY OF TERMS

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

COMPANIES

GENERATING UNITS

REGULATORS

OTHER

NORTHEAST UTILITIES

THE CONNECTICUT LIGHT AND POWER COMPANY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

WESTERN MASSACHUSETTS ELECTRIC COMPANY

2005 Form 10-K Annual Report
Table of Contents

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 199,000 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) and Mode 1 Communications, Inc. (Mode 1).  Holyoke Water Power Company (HWP), a subsidiary of NU, is a resource of NUEI through an output contract with Select Energy.  In 2005, NU decided to exit all its competitive businesses and expects to complete the process in 2006.   

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 and, on a limited basis, to certain other New England utilities.  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).  Pursuant to the Energy Policy Act of 2005, the Public Utility Holding Company Act of 1935 (PUHCA or the 1935 Act), which regulated various aspects of the NU system's operations, was repealed on February 8, 2006 and jurisdiction over a number of areas covered by PUHCA was assumed by the FERC.

For information regarding each of the NU system's reportable segments, see Footnote 17, "Segment Information" contained within NU's 2005 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 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, methods, timing and results of disposition of our competitive businesses, actions of rating agencies, 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.

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 2005, CL&P provided retail franchise service to approximately 1.2 million customers in Connecticut, PSNH provided retail service to approximately 481,000 customers in New Hampshire and WMECO served approximately 209,000 retail customers in Massachusetts.

The following table shows the sources of 2005 electric franchise retail revenues based on categories of customers:

The actual changes in retail kilowatt-hour (kWh) sales for the last two years and the forecasted retail sales growth estimates for the five-year period 2006 through 2010 for CL&P, PSNH and WMECO are set forth below:

Consolidated NU retail sales rose by 2.6 percent in 2005, compared with 2004, but were down 0.1 percent on a weather-adjusted basis.  Residential electric sales were up 4.4 percent.  Commercial sales were up by 3.6 percent for the year and industrial sales decreased by 4.0 percent, due primarily to increases in energy costs, business closings and cogeneration equipment installation.  Retail sales for CL&P, PSNH and WMECO were up 3.0 percent, 1.9 percent and 1.4 percent, respectively.  There is some concern that higher electric and gas rates, driven by higher fuel costs and milder winter weather, could reduce sales in 2006.  

Regional and System Coordination

NU's electric utility subsidiaries and most other New England utilities, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region's generation and transmission facilities and the market rules by which these parties participate in the wholesale markets and acquire transmission services.  Under these arrangements, ISO New England Inc. (ISO-NE), a non-profit corporation whose board of directors and staff are independent from all market participants, has served as the Regional Transmission Operator for New England (RTO) since February 1, 2005.  ISO-NE ensures the reliability of the New England transmission system, administers the independent system operator tariff (ISO Tariff), subject to FERC approval, and oversees the efficient and competitive functioning of the regional wholesale power market.

The ISO Tariff provides for (i) a pool-wide non-discriminatory open access transmission tariff, (ii) a governance structure for stakeholder input into transmission and market rules by the New England Power Pool (NEPOOL) and (iii) market rules facilitating an open, competitive market structure.  The ISO 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 participating transmission owners’ agreement 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, which are part of the ISO Tariff.  NU's local open access transmission tariff is also a formula rate, which was recently restructured to ensure timely recovery of NU's revenue requirements.    

Transmission revenues have been allocated since 2001 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.  

FERC Regulatory Changes

The wholesale transmission revenues of NU's electric utility subsidiaries 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) portion of the ISO Tariff and NU's local network service (LNS) portion of the ISO Tariff.  NU's LNS rate is reset on January 1 and June 1 of each year, while NU's RNS rate is reset on June 1 of each year.  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 return on equity (ROE).  In 2005, this true-up resulted in the recognition of a $2.1 million regulatory liability, including approximately $1.5 million due to NU's electric distribution companies.

As a result of the RTO start-up on February 1, 2005, the ROE in the LNS tariff was increased to 12.8 percent.  The ROE being utilized in the calculation of the current RNS rates is the sum of the 12.8 percent "base" ROE, plus a 50 basis point incentive adder for joining the RTO, or a total of 13.3 percent.  An initial decision by a FERC administrative law judge (ALJ) has set the base ROE at 10.72 percent as compared with the 12.8 percent requested the by New England RTO.  One of the adjustments made by the ALJ was to modify the underlying proxy group used to determine the ROE, resulting in a reduction in the base ROE of approximately 50 basis points.  The ALJ deferred to the FERC for final resolution on the 100 basis point incentive adder for new transmission investments, but reaffirmed the 50 basis point incentive for joining the RTO.  The New England transmission owners have challenged the ALJ's findings and recommendations through written exceptions filed on June 27, 2005 and a final order from the FERC is expected in 2006.  The result of this order, if upheld by the FERC, would be an ROE for LNS of 10.72 percent and an ROE for RNS of 11.22 percent.  When blended, the resulting "all in" ROE would be approximately 11.15 percent for the NU transmission business.  Management cannot at this time predict what ROE will ultimately be established by the FERC in these proceedings, but for purposes of current earnings accruals and estimates, the transmission business is assuming an ROE of 11.5 percent.

Effective February 1, 2006, FERC approved new rates allowing NU to collect 50 percent of the cost of construction work in progress (CWIP) for the major southwest Connecticut transmission projects in its formula LNS rate.

In November 2005, the FERC announced that it was considering a number of proposals to provide financial incentives for the construction of high-voltage electric transmission in the United States.  Those proposals included the reflecting in rate base 100 percent of the cost of CWIP; accelerated recovery of depreciation; imputing hypothetical capital structures in ratemaking; establishing ROEs for transmission owners that join RTOs; and other incentives that could improve the earnings and/or cash flows associated with NU's transmission capital expenditures.  Comments on the FERC proposals were submitted in January 2006 and final rules are expected by the summer of 2006.  

In March 2004, ISO-NE proposed at the FERC an administratively determined electric generation capacity pricing mechanism known as Locational Installed Capacity (LICAP), 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 fixed reserve and contingency margins.

After opposition from state regulators, utilities and various Congressional delegations, the FERC ordered settlement negotiations before an administrative law judge to determine whether there was an acceptable alternative to LICAP.  On March 6, 2006, ISO-NE and a broad cross-section of critical stakeholders from around the region, including CL&P, PSNH and Select Energy, filed a comprehensive settlement agreement at the FERC implementing a forward capacity market (FCM) mechanism in place of LICAP.  The settlement agreement provides for a fixed level of compensation to generators from December 1, 2006 through May 31, 2010 without regard to location in New England, and annual forward capacity auctions, beginning in 2008, for one-year period ending May 31, 2011, and annually thereafter.  The settlement agreement must be approved by the FERC, and the parties have asked for a decision by June 30, 2006. According to preliminary estimates, FCM would require the operating companies to pay approximately the following amounts during the 3½-year transition period:  CL&P - $470 million; PSNH - $80 million; and WMECO - $100 million.  CL&P would be able to recover these costs from its customers through the federally mandated congestion charges (FMCC) mechanism.  PSNH and WMECO also would be able to recover these costs from their customers.

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 but retained its fossil/hydro generation assets.  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.  Legislation has been proposed in New Hampshire that will extend the prohibition against any divestiture until at least July 2008.

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 financed 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, 2005, 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.  PSNH anticipates it will complete recovery of its non-securitized stranded costs during 2006, and will continue to recover its remaining stranded costs including RRB-related charges, nuclear decommissioning and independent power production costs and certain going-forward costs relating to its generating assets.

All of NU's electric operating company customers are now able to choose their energy suppliers, with the electric companies furnishing "transitional 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.

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 transitional standard offer (TSO) rates (2004-2006).  Only a small number of CL&P customers (approximately 33,000 out of nearly 1.2 million at December 31, 2005) have opted for a competitive retail supplier.

In accordance with Connecticut's 2003 electric restructuring legislation, CL&P signed fixed-price contracts with six wholesale suppliers who together will serve all of CL&P's TSO requirements in 2006.  None of CL&P's suppliers for 2006 are 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 protect CL&P from loss in the event any of the suppliers encounters financial difficulties.  CL&P has not filled its generation supply requirements beyond 2006 and will in 2006 initiate new solicitation processes for its future load obligation.  

In December 2003, the DPUC issued a final decision establishing CL&P's retail distribution and transmission rates beginning on January 1, 2004 to cover a four-year period.  The decision approved an ROE of 9.85 percent with earnings above that level to be shared 50/50 between customers and shareholders.  The retail and transmission rates are included in CL&P's total TSO rates.  

In November 2004, the DPUC issued a decision that identified which specific costs imposed on CL&P by the FERC or ISO-NE constitute FMCCs 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 May 16, 2005, the DPUC approved an interim 4.8 percent FMCC rate increase of $79.8 million, effective June 1, 2005, to recover new "reliability must run" costs not included in FMCC rates.  The DPUC approval was affirmed by the DPUC in an order dated August 24, 2005.  On August 1, 2005, CL&P submitted a reconciliation of its FMCC, Energy Adjustment Clause (EAC) and generation services charge (GSC) collections and net expenses for the period of January 1 through June 30, 2005, but proposing no rate change, and is awaiting DPUC action on that filing.  On February 1, 2006, CL&P submitted a reconciliation of its FMCC, EAC and GSC collections and net expenses for the period of January 1 through December 31, 2005, again proposing no rate change, and is also awaiting DPUC action on that filing.

The DPUC issued a final decision in December 2004 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.  An appeal filed by the Office of Consumer Counsel (OCC) with the Connecticut Superior Court challenging this decision was dismissed.

On December 28, 2005, the DPUC issued a final decision setting CL&P's TSO rates for 2006.  The decision approved an increase of approximately 17.5 percent above current TSO rates, effective as of January 1, 2006, and an additional TSO rate increase of approximately 4.9 percent effective as of April 1, 2006.  The increase, amounting to $676.5 million on an annual basis, was necessary to collect higher costs for TSO generation supply.   

In CL&P's 2001 competitive transition assessment (CTA) and systems benefits charge (SBC) reconciliation filing, and subsequently in a 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.  In October 2003, CL&P appealed the DPUC's final decision denying CL&P's request to the Connecticut Superior Court.  A decision from the court is expected to be issued in 2006.  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 2005 impact of including the deferred intercompany liability in CTA revenue requirements has been a reduction of approximately $17 million in revenue.

As a result of Connecticut legislation passed in 2005, CL&P filed for a transmission adjustment clause on August 1, 2005 with the rate tracking mechanism to be effective on July 1, 2005.  The DPUC approved the tracking mechanism, which provides for semi-annual adjustments in January and June, on December 20, 2005.  Effective January 1, 2006 the retail transmission rate was increased to recover an additional $21 million over the first six months of 2006.  CL&P adjusts its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis.

A final decision relating to CL&P's streetlight assets, plant values, accounting practices and rates was issued by the DPUC on June 30, 2005.  The decision addressed, among other things, CL&P's liability for refunds to customers as of a result of past billing errors, and caused CL&P to take a $4.1 million pre-tax reserve.  CL&P's appeal of this decision to the Connecticut Superior Court is pending.  No refunds will be required to be paid until the appeal is resolved.

Connecticut Legislation

On July 6, 2005, Governor Rell signed legislation creating a mechanism to allow the DPUC to true-up, at least annually, the retail transmission charge in local electric distribution company rates based on changes in FERC-approved charges.  This mechanism will allow CL&P to include forward-looking transmission charges in its retail transmission rate and promptly recover its transmission expenditures.  In December 2005, the DPUC approved CL&P's proposal to implement the mechanism.  See "CL&P Retail Rates - CL&P Rate Matters."

On July 21, 2005, Governor Rell signed Public Act 05-01, entitled An Act Concerning Energy Independence (Act).  The Act provides for a variety of measures intended to reduce LICAP costs and other FMCC charges which represent the costs of power market rules approved by the FERC that are resulting in significantly higher costs for Connecticut.  The Act provides for incentives to electric distribution companies for their efforts in facilitating near- and long-term cost reduction measures, creates customer incentives for the development of customer-side and grid-side distributed resources and encourages new generation plants, long-term capacity contracts and

additional conservation measures.  The Act allows CL&P to own up to 200 megawatts (MW) of peaking facilities if the DPUC determines that such facilities will be more cost effective than other options for mitigating FMCCs and LICAP costs.  The DPUC has opened a number of new dockets to implement this legislation.

CL&P Transmission Projects

CL&P has undertaken a substantial transmission construction program over the past several years.  Transmission capital expenditures in Connecticut are focused primarily on four major transmission projects in southwest Connecticut.  These projects include a new 21-mile, 345 kilovolt (kV) project between Bethel, Connecticut and Norwalk, Connecticut, a 69-mile, 345 kV project between Middletown, Connecticut and Norwalk, and a related 115 kV underground project, and the replacement of the 138 kV cable between Connecticut and Long Island.  Each of these projects has received approval from the Connecticut Siting Council (CSC).  Capital expenditures for the southwest Connecticut transmission projects totaled $156 million in 2005, and total transmission expenditures were $207.8 million.  In 2006, CL&P's transmission capital expenditures in southwest Connecticut are projected to total approximately $325 million, and total transmission expenditures are projected to total approximately $400 million.  

The Bethel to Norwalk project is currently projected to cost approximately $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 and the transmission lines is approximately 70 percent complete.  Management estimates a project completion date of December 2006.  At December 31, 2005, CL&P has capitalized $196 million associated with this project.

On April 7, 2005, the CSC unanimously approved a proposal by CL&P and The United Illuminating Company to build a 69-mile, 345 kV transmission line from Middletown to Norwalk, Connecticut.  Approximately 24 miles of the 345 kV line will be built underground with the balance being built overhead.  The project still requires CSC review of detailed construction plans, as well as United States Army Corps of Engineers approval to bury the line beneath certain navigable rivers and Connecticut Department of Environmental Protection (DEP) approvals.  The CSC decision included provisions for low-magnetic field designs in certain areas and made variations to the proposed route.  As a result of increases due to configuration and design specification changes, current competitive bid and construction experience, and commodity price changes, CL&P's portion of the project is now estimated to cost approximately $1.05 billion.  CL&P received final technical approval from ISO-NE on January 20, 2006 and expects to award the major construction-related contracts during the second quarter of 2006.  CL&P expects the project to be completed by the end of 2009.  Three appeals of the CSC decision have been filed, but CL&P does not expect any of these three appeals to delay construction.  At December 31, 2005, CL&P has capitalized $41 million associated with this project.  CL&P anticipates filing its cost allocation proposal with ISO-NE during the fourth quarter of 2006.

In October 2004, CL&P and the Long Island Power Authority (LIPA) jointly filed plans with the DEP to replace an undersea 13-mile electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York, consistent with a comprehensive settlement agreement reached in June 2004.  CL&P and LIPA each own approximately 50 percent of the line.  On June 20, 2005, the New York State Controller's Officer and the New York State Attorney General approved an agreement between CL&P and LIPA to replace the cable.  The CSC has previously approved the project.  State and federal permits are also expected to be issued in the second quarter of 2006.  Assuming these permits are received by no later than the second quarter of 2006 and the necessary construction contracts are signed, construction activities will begin when material lead times allow.  Management will provide the estimated removal and in-service dates when these construction contracts are signed.  At December 31, 2005, CL&P has capitalized $6 million associated with this project.

CL&P's construction of two 115 kV underground transmission lines between Norwalk and Stamford, Connecticut was approved by the CSC on July 20, 2005 and by ISO-NE on August 3, 2005.  There were no court appeals of the project, which is expected to cost approximately $120 million.  Management expects to begin major construction during 2007 and expects the lines to be in service during 2008.  At December 31, 2005, CL&P has capitalized $7 million associated with this project.

In late 2005, CL&P began construction of a new substation in Killingly, Connecticut that will improve CL&P's 345 kV and 115 kV transmission systems in northeast Connecticut.  The project is expected to be completed by the end of 2006 at a cost of approximately $32 million.  At December 31, 2005, CL&P has capitalized $2.5 million associated with this project.

During 2005, CL&P placed in service $175 million of electric transmission projects, including $70 million relating to the Bethel to Norwalk project.

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

Massachusetts Retail Rates

In Massachusetts, as of February 28, 2005, there is only one type of service provided to customers not on competitive supply.  That service, called default or "basic" service, is procured by electric utility companies.  Pursuant to a DTE order issued in 2003, there are

now two separate solicitations for basic service.  

For smaller customers, there are two basic service solicitations each year.  In each of these solicitations, 50 percent of the basic service supply is procured for a twelve-month period; the rates in effect at any one time are an average of the prices obtained in two separate solicitations.  Basic service rates have been approved for smaller customers for the period January 1, 2006 through June 30, 2006.  The suppliers are unaffiliated entities.  The next basic service solicitation for smaller customers will take place in spring 2006.

On December 29, 2005, the DTE approved new rates for WMECO effective January 1, 2006, which included a previously approved $3 million distribution rate increase and the costs of new basic service mentioned above.  Overall average rates for all customers increased by 44 percent as a result of increased energy costs.  Under the December 2004 settlement which allowed the $3 million increase, WMECO agreed not to file for another distribution rate increase to be effective prior to January 1, 2007.

For larger customers, WMECO basic service is procured for a three-month period.  Basic service has been procured and rates approved for larger customers for the period of January 1, 2006 through March 31, 2006.  A single unaffiliated entity is the supplier.  In addition, basic service has now been procured and rates were approved by the DTE on February 17, 2006 for larger customers for the period of April 1, 2006 through June 30, 2006.  A single unaffiliated entity is the supplier.  Reflecting market prices, the approved basic service rates for larger customers for the April through June period are significantly lower than the January through March rates.  The decrease in the basic service rate for these customers will be approximately 44 percent.

WMECO has pending before the DTE its 2004 transition cost reconciliation filing made on March 31, 2005, which seeks to true up a variety of 2003 and 2004 costs.  Management does not expect this proceeding to materially affect WMECO.

New Hampshire Retail Rates

Under the terms of the "Agreement to Settle PSNH Restructuring" (Restructuring Agreement), PSNH files for approval of updated transition energy service and default energy service rates (known collectively as energy service rates or ES) periodically with the NHPUC to ensure timely recovery of its costs.  The ES rate recovers PSNH's generation and purchased power costs, including a return on PSNH's generation assets.  PSNH defers for future recovery or refund any difference between its ES revenues and the actual costs incurred.

On January 28, 2005, the NHPUC issued an order approving an ES rate of $0.0649 per kWh for the period February 1, 2005 through January 31, 2006, which included an 11 percent ROE on PSNH's generation assets.  An NHPUC order changing the ES rate to $0.0724 per kWh became effective on August 1, 2005.  

The NHPUC conducted a separate proceeding to determine a new ROE for PSNH generation.  On December 2, 2005, the NHPUC issued an order that modified the ROE calculation and required PSNH to use a generation ROE rate of 9.62 percent, effective August 1, 2005.  PSNH sought rehearing of this decision and simultaneously filed an appeal with the New Hampshire Supreme Court.  On February 10, 2006, the NHPUC denied PSNH's motion for reconsideration.  The appeal to the New Hampshire Supreme Court remains pending.  

On January 20, 2006, the NHPUC approved new ES rates of $0.0913 per kWh for the period February 1, 2006 through December 31, 2006.  This approval was facilitated by a December 14, 2005 stipulation and settlement agreement between PSNH, the NHPUC staff and New Hampshire Office of Consumer Advocate (OCA), which also allowed PSNH to implement deferred accounting treatment for its asset retirement obligations.

The stranded cost recovery charge (SCRC) allows PSNH to recover its stranded costs.  On an annual basis, PSNH files with the NHPUC a SCRC reconciliation filing for the preceding calendar year.  This filing includes the reconciliation of stranded cost revenues and costs and ES revenues and costs.  The cumulative deferral of SCRC revenues in excess of costs was $303.3 million at December 31, 2005.  This cumulative deferral will decrease the amount of non-securitized stranded costs that will have to be recovered from PSNH's customers in the future from $368.0 million to $64.7 million.

The 2004 SCRC reconciliation filing was filed with the NHPUC on May 2, 2005.  Pursuant to a settlement among PSNH, the NHPUC staff and the OCA, PSNH will be allowed to recover its 2004 ES and stranded costs without disallowances and to include its cumulative unbilled revenues in its ES and stranded cost reconciliations.  The NHPUC approved the settlement agreement as filed on December 22, 2005.  

The NHPUC deferred any action regarding PSNH's coal supply and transportation procedures until it completes a review using an outside expert.  While management believes PSNH's coal procurement and transportation policies and procedures are prudent and consistent with industry practice, it is unable to determine the impact, if any, of this review on PSNH's net income or financial position.

COMPETITIVE ENERGY BUSINESSES

NU is engaged in the retail and wholesale marketing of electricity and natural gas in the northeastern United States, the generation of electricity and the provision of energy related services to large government, industrial, commercial and institutional facilities.  In 2005, NU decided to exit all of its competitive businesses.  NU expects to complete the divestiture of substantially all of its competitive businesses by the end of 2006.  NU's principal objectives in deciding to exit its competitive businesses were:

·

To transition toward a simplified, 100% regulated business model,

·

To reduce its general business risk profile and increase its financial flexibility,  

·

To strengthen its balance sheet in order to finance its utility subsidiaries’ capital expenditure programs,

·

To enhance its earnings visibility and predictability and

·

To capitalize on the value of its generation assets in New England.

See "Status of Divestitures" below for further information.

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 the northeastern and middle Atlantic states. The generation operations of HWP are also included in the results of NUEI.  NUEI and its integrated competitive energy business affiliates had aggregate revenues (excluding revenues from discontinued operations) of approximately $2.0 billion in 2005 as compared to approximately $2.7 billion in 2004 and had losses of $398.2 million in 2005, as compared to a loss of approximately $15.1 million in 2004.

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 146 megawatts (MW) of coal-fired generation at the Mt. Tom station in Holyoke, Massachusetts (Mt. Tom Station) under an evergreen contract.  Pending their sale, the output from NGC's assets and the Mt. Tom Station is being sold in the forward or spot markets while the retail marketing business is servicing its requirements in the spot market and is no longer committed to serving Select Energy load.  See Exhibit 99.1 for certain NGC financial information.

Status of Divestitures

On March 9, 2005, NU announced that NUEI would exit its wholesale marketing business, which it conducts through its subsidiary, Select Energy, and its competitive energy services businesses.  On November 7, 2005, NU announced its decision to exit the remainder of its competitive businesses, which includes its competitive generation and retail marketing businesses.  NU intends to apply the net proceeds from the divestiture of its competitive businesses to debt reduction and the financing of the regulated businesses’ capital spending programs.  See "Construction and Capital Improvement Program."  

Set forth below is an overview of the status of the divestiture process.  For further information relating to these businesses, including 2005 results, see "Merchant Energy," "Retail Marketing,"  "Merchant Generation," "Wholesale Marketing" and "Energy Management and Other Businesses" below.  

Wholesale marketing.  In 2005, NUEI paid or agreed to pay approximately $242 million to complete the divestiture of its New England wholesale sales contracts.  All but approximately $56 million of that sum was paid in 2005.  NUEI continues to negotiate with counterparties to divest its remaining wholesale power obligations in the Pennsylvania-New Jersey-Maryland (PJM) power pool, which expire in 2008, and in New York, where its single contract expires in 2013.

Retail marketing.  NU has retained J. P. Morgan Securities, Inc. (JPMorgan) as its financial advisor in the divestiture of the retail marketing business, which provides electricity and natural gas service to approximately 30,000 customer locations in the New England, New York and PJM power pools.  Indicative bids have been received and NU expects to complete the sale of this business in mid-2006.  

Competitive generation.  JPMorgan has also been retained by NU to act as its financial advisor in the divestiture of its competitive generation, which includes NGC's 1,296 megawatts of competitive generation assets in Massachusetts and Connecticut.  NU expects to complete the sale of this business by the end of 2006.

Energy services businesses.  In 2005, NU sold two of its six competitive energy services businesses, Woods Network Services, Inc. and the New Hampshire operations of Select Energy Contracting, Inc. (SECI-NH) for a total of approximately $6.5 million.  In January 2006, the Massachusetts service location of Select Energy Contracting - Connecticut (SECI - CT), a division of SECI, was sold for approximately $2 million.  NU expects to complete the sale of SESI and Woods Electrical Company, Inc. (Woods Electrical) in 2006.  The sale or closure of NUEI's two remaining energy services businesses, Select Energy Contracting, Inc. - Connecticut and E.S. Boulos Company (Boulos), will be actively pursued during 2006.

Merchant Energy

NUEI, through Select Energy, sells multiple energy products including electricity and natural gas to 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 competitive energy business, Select Energy contracted in December of 1999 with NGC to purchase and market all of NGC's 1,296 MW for an initial five-year period, which contract has been extended through December 2008.  In addition, Select Energy purchases approximately 146 MW of coal-fired generation output from its affiliate, HWP, on a year-to-year basis and additional supply from other suppliers as needed to meet its load obligations.  In some instances, 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 2005, Select Energy reported revenues of $1.9 billion and had retail and wholesale marketing sales of approximately 32,000 gigawatt-hours (gWh) of electricity and 64 billion cubic feet (BcF) of natural gas to approximately 31,000 customers.  During 2004, Select Energy reported revenues of $2.6 billion and had retail and wholesale marketing sales of approximately 41,000 gWh of electricity and 57 BcF of natural gas to approximately 30,000 customers.

In general, the lower level of revenues at NU Enterprises and Select Energy reflects the decision to exit the wholesale marketing business in 2005 and the sale and roll-off of the remaining contractual obligations, partially offset by increased retail marketing revenues.

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 44 electric distribution companies and 39 gas distribution companies to provide retail services.

Select Energy's retail marketing business had a $1.4 million improvement in performance during 2005, with net income of $6.3 million versus net income of $4.9 million in 2004 after adjusting for the effect of realizing certain in-the-money supply contracts in early 2005.  When the effects of realization of these contracts are included in retail marketing's 2005 results, it lost $22.8 million.  The stronger performance is attributed to expense reduction.  

As of December 31, 2005, Select Energy had contracts with retail electric customers throughout the Northeast who utilized over 2,000 MW of peak load at approximately 16,000 locations, including predominately commercial, industrial, institutional and governmental accounts.  During 2005, delivered retail electricity increased 6 percent from 2004 to about 11 million megawatt-hours (MWh).  No single retail electric customer accounted for more than ten percent of Select Energy's retail revenues.

During 2005, Select Energy's competitive natural gas business, which is primarily retail in nature, produced revenues of approximately $600 million, an increase from 2004 revenues of approximately $410 million.  This increase relates to both higher gas prices and higher gas volumes.  In 2005, Select Energy provided approximately 46 BcF of natural gas to approximately 15,000 retail gas customers, primarily located in Connecticut, Massachusetts, New York and Pennsylvania, compared to approximately 39.5 BcF in 2004.  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.  

NU Enterprises is in the process of selling the retail business and expects to close on the sale in mid-2006.  Because the business will likely be sold without benefit of either economic supply entitlements or output from NU Enterprises’ generation resources, the retail portfolio is substantially out of the money and the sale of the business could require NU to make a significant payment to the buyer.

Merchant Generation

NGC, NU's merchant 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, extending through 2008.  Select Energy's

performance under its contract with NGC is guaranteed by NU.  Select Energy also buys and manages the entire generation output of approximately 146 MW from HWP's Mt. Tom generating plant under a contract renewable on an annual basis.  Pending sale of its competitive generation assets, Select Energy has sold a small portion of the NGC and Mt. Tom generation in the forward markets and sells the balance bilaterally or in the spot market.  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 2008, but is expected to be terminated upon the sale of NGC.  During the remaining term, most 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 revenues are in the form of monthly payments at predetermined rates per unit of actual energy output.  This contract provides NGC with a stable stream of revenues, but at prices that at times are higher than average wholesale electricity prices in the markets served by NGC's facilities.

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

The value of NGC's generating assets could be affected by the adoption of FCM in place of the prior LICAP proposal.  See "Regulated Electric Operations - FERC Regulatory Charges."

Wholesale Marketing

In 2005, Select Energy supplied more than 16,000 GWh of standard offer and default service load in New England and the PJM power pool, compared to 24,300 gWh in 2004, reflecting the wind down of this business.

During 2005, the wholesale marketing business lost $349 million, primarily due to having to mark to market and exit its wholesale portfolio during a period of extreme price volatility.  In 2004, that business lost $17 million 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 levels of wholesale electric load in New England.

In 2005, Select Energy revenues from CL&P were approximately $53.4 million, compared to approximately $611.3 million in 2004.

Competitive Energy Subsidiaries’ Market and Other Risks

Implementation of the decision to divest all of its competitive businesses will change the risk profile of NUEI.  NUEI will continue to be exposed to certain market risks under its remaining wholesale contracts until they expire or are divested; however, those risks will be reduced as these contracts are settled or expire.  The merchant energy business segment is comprised of the wholesale marketing business, generation assets and the retail marketing business, 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 the merchant energy business segment.  A significant portion of the retail and marketing business is providing full requirements service to customers, primarily commercial, industrial, institutional and governmental accounts.  The wholesale business is still obligated to supply a number of regulated distribution companies and agencies on such basis.  The "full requirements" obligation commits Select Energy 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.

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.

Until the exit from the merchant energy business is completed, NU Enterprises will continue to be exposed to various market risks which could negatively affect the value of its remaining assets.  These assets include its remaining portfolio of wholesale energy contracts, its retail energy marketing business and its generation assets.  Market risk at this point is comprised of the possibility of adverse energy commodity price movements and, in the case of the wholesale marketing business, unexpected load ingress or egress, affecting the unhedged portion of these assets.  

NU Enterprises manages these and associated operating risks through detailed operating procedures and an internal review committee.  A separate, parent-level committee, the Risk Oversight Council (ROC), meets monthly with NU Enterprises’ leadership and upon the occurrence of specific portfolio-triggered events to review conformity of NU Enterprises’ activities, commitments and exposures to NU's risk parameters.  The ROC in turn is being integrated into NU's enterprise risk management system, which was instituted in 2005.

Energy Management Services and Other Businesses

NUEI has four affiliated companies in the energy related services business: Boulos, Woods Electrical, SESI and SECI.

Wholly-owned subsidiaries, Boulos and Woods Electrical, provide 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 which was sold in 2005.

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.  In 2005, SESI had revenues of approximately $71.2 million.

SECI provides service contracts and mechanical and electrical contracting, primarily directed to energy systems in commercial markets.  SECI's New Hampshire operations were sold in 2005.  In 2005, SECI had revenues of approximately $69.7 million.

Mode 1 is a telecommunications subsidiary of NUEI, which, at January 1, 2005 held a $9.8 million investment in NEON Communications, Inc. (NEON).  NEON is a wholesale provider of high bandwidth communication services to customers in the Northeast and middle Atlantic states utilizing a portion of the NU system companies’ transmission and distribution facilities.  Effective March 8, 2005, NEON merged with Globix Communications, Inc. (Globix), a website hosting company, with Mode 1  receiving Globix shares equal to about five percent of Globix's outstanding shares.  Due to a decline in the value of Globix shares after the merger, NU recognized pre-tax impairment charges of $6.1 million in 2005.  Mode 1's investment in Globix at December 21, 2005 totaled $3.7 million.

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 2005 was 47.7 BcF.  In 2005, total gas operating revenues of $503.3 million were comprised of the following: 47 percent residential; 28 percent commercial; 21 percent industrial; and the remaining 4 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 other market participants to reduce its overall gas expense.

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.  

Yankee Gas is constructing a liquefied natural gas (LNG) facility in Waterbury, Connecticut capable of storing the equivalent of 1.2 billion cubic feet of natural gas.  Construction of the facility began in March 2005 and is expected to be completed in time for the 2007-2008 heating season.  At December 31, 2005, the project was approximately 44 percent complete.  The facility is expected to cost approximately $108 million.  Through December 31, 2005, Yankee Gas has capitalized $46.4 million related to this project.  In 2005, Yankee Gas also spent $41.6 million on reliability improvements, new customer connections and other initiatives.

In December 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 allowed ROE of 9.9 percent.  Yankee Gas agreed not to file a new application for a rate increase that would become effective prior to the earlier of  the in-service date of the LNG or July 1, 2007.  

On December 23, 2005, the DPUC denied a motion by Yankee Gas for interim rate relief of $12.4 million, on or before January 12, 2006, stating that the circumstances presented by Yankee Gas’ filing did not rise to the level of a force majeure contemplated by the rate settlement as a prerequisite to such a filing.  Yankee Gas now expects to file a rate case in late 2006, with new rates to be effective the earlier of July 1, 2007 or the in-service date of the LNG facility.  

In a separate proceeding, Yankee Gas has filed supplemental information regarding $9 million of previous gas revenues recovered through its purchased gas adjustment clause during the period from September 1, 2003 to August 31, 2004.  Based on the facts of the case and the supplemental information provided to the DPUC, management believes the appropriateness of the charges to customers for the time period under review will be approved.

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

FINANCING PROGRAM

2005 Financings  

On April 7, 2005, CL&P issued $100 million of first mortgage bonds (the Series A Bonds) with a coupon of 5.000 percent and a maturity of April 1, 2015.  CL&P also issued $100 million of first mortgage bonds (the Series B Bonds) with a coupon of 5.625 percent and a maturity of April 1, 2035.  The proceeds of both issuances were used to refinance the company's short-term borrowings, which were previously incurred to fund transmission and distribution capital expenditures.  

On July 6, 2005, CL&P entered into an agreement to extend the bank commitment for its $100 million accounts receivable sale program for an additional 364 days, through July 5, 2006.  The program is scheduled to remain in effect until July 3, 2007 but may be extended.

On July 21, 2005, Yankee Gas issued $50 million of first mortgage bonds (the Series I Bonds) with a coupon of 5.350 percent and a maturity of July 15, 2035.  The proceeds of the transaction were used to refinance the company's short-term debt and to fund its capital expenditures.

On August 11, 2005, WMECO issued $50 million in senior unsecured notes (the Series C Notes) with a coupon of 5.240 percent and a maturity of August 1, 2015.  The proceeds of this issuance were used to refinance the company's short-term debt previously incurred to fund capital expenditures.

On October 5, 2005, PSNH issued $50 million of first mortgage bonds (the Series M Bonds) with a fixed coupon of 5.60 percent and a maturity of October 5, 2035.  The proceeds of this issuance were used to refinance the company's short-term debt and to fund its capital expenditures.

On November 2, 2005, NU entered into an unsecured $600 million, 364-day credit facility, which was reduced following the increase in NU's five-year revolver and equity issuance and presently provides a total commitment of $310 million in long-term borrowings and letters of credit.  This facility will expire no later than November 30, 2007, although no advances or letters of credit will be available under the facility beyond October 30, 2006.

On December 9, 2005, CL&P, WMECO, PSNH and Yankee Gas amended their unsecured five-year revolving credit facility for $400 million by extending the expiration date by one year to November 6, 2010.  The companies 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 from this facility, subject to the $400 million maximum for the entire facility.  

On December 9, 2005, NU amended its unsecured five-year revolving credit facility by extending the expiration date to November 6, 2010 and by increasing its borrowing limit from $500 million to $700 million.  The company will be able to borrow from this facility on a short-term basis and, subject to certain conditions, on a long-term basis.  The amended facility provides a total commitment of $700 million with a $550 million sub-limit for letters of credit.  

On December 12, 2005, NU issued 23 million common shares at $19.09 per share ($5 par value) for total proceeds of $439.1 million, before underwriting discounts and expenses.  The net proceeds will be used to finance the capital expenditures of the regulated subsidiaries and to finance the exit from the company's competitive businesses.

NU paid common dividends totaling $87.6 million in 2005, compared to $80.2 million paid in 2004, reflecting increases in the quarterly dividend rate that were effective September 30, 2005 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, 2005 (excluding SESI debt), compared with $3.1 billion as of December 31, 2004.

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."  

2006 Financing Requirements  

The NU system's aggregate capital requirements for 2006 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 2006 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."  

2006 Financing Plans

CL&P plans to issue up to $250 million of long-term debt in 2006, primarily to finance its distribution and transmission businesses and for general corporate purposes.  See "Construction and Capital Improvement Program."

The Rocky River Realty Company (RRR) plans to issue up to $25 million of long-term debt to refinance short-term debt and for general corporate purposes.

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 Credit Facilities

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, 2005, CL&P's, WMECO's, PSNH's, and Yankee Gas' leverage ratios were 48 percent, 55 percent, 54 percent and 41 percent, 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 364-day and five-year revolving credit agreement facilities, to maintain a debt to total capitalization (leverage ratio) of no more than 70 percent through December 31, 2005, 67.5 percent through March 31, 2006 and 65.0 percent thereafter.  At December 31, 2005, NU's leverage ratio was 60 percent.  The ratio does not include RRBs and RRCs.

Short-Term Debt Limits

The amount of short-term debt that may be incurred by NU, CL&P, WMECO, Yankee, Yankee Gas and HWP was subject to approval by the SEC under the 1935 Act during 2005.  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.  On October 28, 2005, the SEC issued an order adding the North Atlantic Energy Service Corporation (NAESCO) as a participant in the Money Pool, increasing HWP's short-term debt authority from $10 million to $35 million, and increasing NU's borrowing authority from $450 million to $700 million.  Although the 1935 Act was repealed as of February 8, 2006, under the FERC's transition rules all of the existing orders under the 1935 Act relevant to FERC authority will continue to be in effect until December 31, 2007, except for those related to NU, Yankee Gas and Yankee, which have no SEC or FERC borrowing limitations after February 8, 2006.  Yankee Gas’ long-term debt issuances will continue to be regulated by the DPUC.  The DPUC does not regulate Yankee Gas’ short-term debt issuances.  Except for PSNH, the remaining operating companies will be subject to FERC jurisdiction as to issuing short-term debt after February 8, 2006 and must renew any short-term debt authority after the 1935 Act order expires on December 31, 2007.  NU, Yankee Gas, NGC and Mode 1 may lend to, but may not borrow from, the Money Pool under the present Money Pool terms.  The following table shows the amount of short-term borrowings authorized for each company, as the case may be, as of December 31, 2005, and the amounts of outstanding short-term debt of those companies at the end of 2005 and as of March 1, 2006 (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 $32 million at December 31, 2005 and $218 million at March 1, 2006.

(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 a superseding 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 were subject to periodic approval by the SEC under the 1935 Act prior to its repeal.

(3)

Pursuant to a DTE order, WMECO can lend through the Money Pool only to CL&P, HWP, Northeast Nuclear Energy Company (NNECO), Quinnehtuk and RRR.

(4)

Includes RRR, Quinnehtuk, Yankee Energy Financial Services Company, Yankee, NorConn Properties, Inc., NUEI, NGS, Boulos, Woods Electrical, Select Energy, North Atlantic Energy Corporation  (NAEC), NNECO, Select Energy New York, Inc., SESI, Properties, Inc. and NAESCO.

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, 2005, the amount of additional unsecured debt it could incur was $531.9 million.

CL&P's first mortgage bond indenture was amended in April 2005, with the consent of a majority of its outstanding bondholders, to eliminate certain restrictions and change the methodology for determining the amount of secured debt that can be issued and the amount of assets that can be sold under the indenture.  The new methodology requires CL&P to pass a "75 percent test", in which after giving effect to any new issuance or asset sale, the company's outstanding mortgage bonds must be less than 75 percent of its net plant.  At December 31, 2005, CL&P's outstanding mortgage bonds were 30.3 percent of its net plant.

Yankee Gas’ 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) Yankee Gas has available property credits equal to 166 2/3 percent of the principal amount of bonds to be issued.  The 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, 2005, Yankee Gas' net earnings were 2.48 times the annual interest charges on its outstanding bonds.  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, 2005, 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.

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, 2005, CL&P's income before interest charges was approximately 2.44 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, 2005, retained earnings available for the payment of dividends totaled $330.4 million.

The Federal Power Act limits the payment of dividends by PSNH, CL&P, WMECO and Yankee Gas to retained earnings.  At December 31, 2005, retained earnings available for the payment of dividends for these companies were $232.1 million, $382.6 million, $85.0 million and $38.5 million, respectively.  Similar restrictions in the 1935 Act were eliminated with the repeal of the 1935 Act on February 8, 2006.

PSNH is 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, 2005, NGC's contracted generating capacity was greater than 75 percent.  NGC expects to meet its debt service coverage ratio requirements under this covenant and to pay dividends in 2006.

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.  WMECO obtained a similar SEC consent on August 31, 2005.  As of December 31, 2005, NU's, CL&P's, WMECO's and PSNH's ratios were 34.9 percent, 32.1 percent, 31.7 percent and 33.3 percent, respectively.  These ratios include RRBs and RRCs as debt.  With the repeal of the 1935 Act on February 8, 2006, this restriction is no longer directly applicable, and the FERC has no similar requirement.

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.  At December 31, 2005, the maximum level of exposure in accordance with the Financial Accounting Standards Board (FASB) Interpretation No. 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 $989.7 million.  Computations under FIN 45 include all exposures even though they are not reasonably likely to result in exposure to NU.  Additionally, NU had $253 million of letters of credit issued at December 31, 2005, the majority of which were issued for the benefit of the unregulated subsidiaries.

NU received authorization from the SEC under the 1935 Act to provide up to $750 million of such guarantees for the benefit of its unregulated subsidiaries through June 30, 2007.  As of December 31, 2005, the value of guarantees outstanding under this limit was $567.5 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, 2005, $0.2 million of guarantees were outstanding for the regulated entities.  These amounts are calculated using separate, more probabilistic and fair value-based criteria than the maximum level of exposure required to be disclosed under FIN 45.  FIN 45 requires the inclusion of all exposures without taking into account the likelihood of these exposures resulting in an actual cost to NU.  

In October 2004, the SEC authorized NU under the 1935 Act 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, 2005 was $0.2 million.

Due to repeal of the 1935 Act on February 8, 2006, NU is no longer limited in the amount of guarantees it can issue.

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 $1.41 billion 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.  Were NU's unsecured ratings to decline one level to sub-investment grade, Select Energy could, under its present contracts, be asked to provide approximately $407 million of collateral or letters of credit to various unaffiliated counterparties as of December 31, 2005, and approximately $96 million to several independent system operators and unaffiliated local distribution companies as of December 31, 2005, which management believes NU would currently be able to provide.  At December 31, 2005, Select Energy could have been requested to provide $12.7 million of collateral under certain contracts which counterparties have not required to date.  NU's credit ratings are currently investment grade and its ratings outlooks are currently stable.  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 senior secured debt that can be funded with cash, an NU guarantee (if NU has an investment grade rating by Standard & Poor's and Moody’s Investors Service (Moody's) or a letter of credit (LOC) from an acceptable counterparty.  The account is currently funded with a guarantee from NU.  If NU were to be downgraded below investment grade, NGC

would then be required to substitute cash or an LOC for this guarantee.

RRR is a real estate subsidiary that owns NU's Connecticut headquarters site.  As of December 31, 2005, it had approximately $2.3 million of debt outstanding that could be affected by a ratings change.  If 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.

CONSTRUCTION AND CAPITAL IMPROVEMENT PROGRAM

The NU system's construction program expenditures are estimated to total approximately $900 million in 2006.  Of such total amount, approximately $600 million is expected to be expended by CL&P, $150 million by PSNH, $100 million by Yankee Gas and $50 million by WMECO.  This construction program data includes all anticipated costs necessary for committed projects and for those reasonably expected to become committed projects in 2006, 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 2006 in light of future developments, such as restructuring, industry consolidation, performance and other events.

CL&P plans to invest approximately $1.2 billion during the period from 2006 to 2010 to construct two new 345 kV transmission lines from inland Connecticut to Norwalk, Connecticut and $120 million for a related 115 kV underground project to meet growing electric demands in the area.  Approximately $60 million to $70 million will be invested in this period 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 investment in electric plant by approximately $3.1 billion over the 2006 through 2010 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 investment in electric transmission would increase by nearly $2.3 billion by the end of 2010.  See "Regulated Electric Operations-Connecticut Retail Rates."

In October 2004, PSNH received the approvals necessary to begin construction related to the conversion of one of three 50 megawatt units at the coal-fired Schiller Station to burn wood.  Construction of the $75 million Northern Wood Power Project began in 2004 and significant construction has been completed.  The project is expected to achieve commercial operation in the second half of 2006.  Construction-related expenditures for 2006 are estimated to total $10.3 million.  This project was approximately 86 percent complete on December 31, 2005.  As of December 31, 2005, PSNH has capitalized $64.7 million related to this project.

Yankee Gas will continue to emphasize system expansion of its natural gas distribution system in Connecticut and has received DPUC support for the installation of a liquefied natural gas production and storage facility in Waterbury, Connecticut capable of storing the equivalent of 1.2 billion cubic feet of natural gas and estimated to cost approximately $108 million.  Construction began in March 2005 and the facility is approximately 48 percent complete.  The plant is expected to be in service for the 2007/2008 heating season.

NUCLEAR ACTIVITIES

General

During 2005, 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 (YA).  YA, 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.

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 operating 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, with the companies’ aggregate damages estimated at between $523 million and $543 million.  The trial addressing these issues concluded on August 31, 2004 and 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 CY, YA and MY.  All of the spent fuel has been moved to the respective storage sites for CY, YA and MY as of April 2005, June 2003 and February 2004, respectively.  

Decommissioning

NU has significant decommissioning and plant closure cost obligations to CYAPC, YAEC and MYAPC, each of which collects these 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 - 2005, 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, liability and property insurance and soil remediation.  

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.  NU's share of these increased costs would be approximately $194 million.  In July 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.  In August 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund, and held hearings in the spring of 2005.  On November 22, 2005, the FERC trial judge issued an initial decision finding CYAPC's actions were prudent and that an increase in decommissioning collections was warranted.  However, the judge also found that the total dollars requested should reflect a lower escalation rate, which reduces the collections by approximately $38 million.  A final order is expected later in 2006.  The FERC rejected other proceedings brought by certain intervenors with respect to the recoverability of the decommissioning costs from retail ratepayers.  The FERC's action is currently on appeal to the federal court.    

NU cannot at this time predict the timing or outcome of the final FERC order.  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 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.  For further information on this proceeding, see Item 3, "Legal Proceedings."

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.  

On November 23, 2005, YAEC filed a request with the FERC for recovery of additional decommissioning-related costs totaling $192.1 million (stated on a 2006 dollar basis) for completing site closure activities from October 2005 forward and storing spent nuclear fuel and other high level nuclear waste on site until 2020.  NU's share of such costs would be approximately $74 million.  On January 31, 2006, the FERC accepted the higher rates sought by YAEC, effective February 1, 2006, subject to refund after FERC hearings.  The hearings have been suspended pending settlement discussions between YAEC, the FERC and other intervenors.

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, 2005, 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 YA, CY and MY as of December 31, 2005, which have been recorded as an obligation on the books of the NU system companies.

As of December 31, 2005, 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:

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

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 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 and may require further significant expenditures, which are difficult to estimate, 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.  

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 $28 million during 2005: approximately $17 million for PSNH and approximately $11 million for HWP.  

Massachusetts has recently imposed significant new emission reduction requirements on power plants, in addition to the Federal requirements.  The four pollutants regulated under standards signed into law in September 2001 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 the Mt. Tom Station.  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 for installation of a selective catalytic reduction (SCR) system to meet the new emission standards.  Completion of this work, expected in mid-2006, will reduce the Mt. Tom Station'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 and reduction allowances.  Additional costs for compliance with mercury requirements are unknown at this time.  Effective January 1, 2006, new CO2 requirements for power plants became effective, limiting emissions from the Mt. Tom Station.  The MDEP has also proposed trading rules that, if passed, may further define compliance options.

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.  In November 2005, PSNH and various legislative, state government and environmental leaders announced that they had reached a consensus to propose legislation to reduce the level of mercury emissions from PSNH's coal-fired plants by 2013 with incentives for early reduction.  As part of the proposed legislation, PSNH's primary long-term alternative to comply with the proposed legislation would be to install wet scrubber technology at its two Merrimack coal units, which have a combined capacity of 433 MW, at a cost of approximately $250 million.  The proposed legislation is being considered during the 2006 legislative session.  

The Regional Greenhouse Gas Initiative (RGGI) is a cooperative effort by nine northeastern states including New Hampshire and Connecticut to develop a regional program for stabilizing and reducing CO2 emissions from fossil-fired electric generators.  This initiative proposes to stabilize CO2 emissions at current levels and require a ten percent reduction by 2020.  The RGGI agreement (MOU) was signed on December 20, 2005 by the states of Connecticut, Delaware, Maine, New Jersey, New Hampshire, New York and Vermont.  Each signatory state committed to propose for approval legislative and/or regulatory mechanisms to implement the program.  RGGI may impact PSNH's Merrimack, Newington and Schiller stations.  At this time, the impact of this agreement on NU cannot be determined.    

Hazardous Materials Regulations

Prior to the last quarter of the 20^th century when environmental best practices and laws were implemented, NU system companies, like most industrial 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, 2005, 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 $30.7 million, representing 52 sites.  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, 2005, the NU system was involved in four Superfund matters: 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 $0.7 million for its share of the clean up of these sites.  

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's.  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 28 former MGP sites.  Of the total NU system liabilities, a reserve of approximately $25.3 million has been established to address future investigation and/or remediation costs at MGP sites, of which $17.7 million is for Yankee Gas 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 thirteen miscellaneous projects.  To date, a reserve of approximately $4.75 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 9B, "Commitments and Contingencies - Environmental Matters" contained within NU's 2005 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.

The NU system companies have closely monitored research and government policy developments for many years and will continue to do so.  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.  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 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 2004, Connecticut enacted legislation designed to reduce the magnetic field exposure associated with new transmission lines of 345 kV and above on a precautionary basis.  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 - CL&P Transmission Projects."  In addition, the CSC is currently conducting a proceeding to adopt "EMF best management practices" to identify transmission facility design strategies to address the perceived but uncertain risks of EMF when constructing new transmission facilities.  

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, Vermont 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, 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 Connecticut Department of Environmental Protection (DEP) 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 required to be operational in 2005 were placed in operation in accordance with a FERC approved plan.  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.  NGC is in the process of preparing and filing these plans, and a number of plans have been reviewed and approved by the FERC.  NGC received an extension until April 2006 for the filing of the shoreline management plan.

PSNH's FERC license for the Merrimack River Hydroelectric Project that consists of the Amoskeag, Hooksett and Garvins Falls hydroelectric generating stations expired on December 31, 2005.  In December 2003, PSNH filed an application for a new license for the project.  The FERC issued a notice that the project was ready for environmental analysis in March 2005.  In response to the FERC's notice, comments were filed by various parties to the proceeding, including the filing of a preliminary fishway prescription by the United States Fish and Wildlife Service (USFW).  On December 19, 2005, in accordance with new regulations issued by the Departments of Agriculture, Interior and Commerce regarding appeal of mandatory license conditions and prescriptions, PSNH submitted an alternative fishway prescription and filed a request for a hearing on disputed issues of material fact related to USFW's preliminary fishway prescription.  The environmental assessment for the project was issued on January 24, 2006 and a 30-day comment period has expired.  The current project license expired on December 31, 2005 and FERC issued an annual license for the project on January 19, 2006 on terms and subject to conditions substantially similar to the previous 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, any estimates of the cost of project decommissioning are preliminary and subject to change as new information becomes available.

EXECUTIVE OFFICERS OF NU

          Name          

Age

Business Experience During Past 5 Years

Gregory B. Butler

48

Senior Vice President and General Counsel of NU since December 1, 2005 and of CL&P, PSNH and WMECO since March 9, 2006, and a Director of Northeast Utilities Foundation, Inc. since December 1, 2002; previously Senior Vice President, Secretary and General Counsel of NU from August 31, 2003 to December 1, 2005; 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

58

President-Competitive Group of NU and President of NU Enterprises, Inc., since October 25, 2004 and Chairman, President and Chief Executive Officer 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.

Cheryl W. Grisé (*)

53

Executive Vice President of NU since December 1, 2005; 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 - Utility Group of NU from May 2001 to December 1, 2005; 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.

Gary A. Long (**)

54

President and Chief Operating Officer and a Director of PSNH since July 1, 2000; previously Senior Vice President - 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

45

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 from July 1998 to December 31, 2004.

Raymond P. Necci

54

President and Chief Operating Officer and a Director of CL&P since January 17, 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

57

Executive Vice President of NU since December 1, 2005; Director of WMECO and PSNH since January 17, 2005 and a Director of CL&P since September 2001.  Previously President - Transmission Group of NU from January 17, 2005 to December 1, 2005; 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

53

President and Chief Operating Officer 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 (***)

60

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 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.  

John P. Stack (****)

47

Vice President - Accounting and Controller of NU, CL&P, WMECO and PSNH since January 2002.  Previously Executive Director - Corporate Accounting and Taxes from 1998 to January 2002.

 (*)

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.

(****)

Mr. Stack is on the Board of the Connecticut Hospice and Chairman of its Audit and Finance Committee.

EMPLOYEES

As of December 31, 2005, the NU system companies had 6,879 employees on their payrolls, excluding temporary employees, of which 2,194 were employed by CL&P, 1,332 by PSNH, 418 by WMECO, 469 by Yankee Gas, 207 by NGS, 1,599 by NUSCO, 135 by Select, 111 by SESI, 161 by SECI, 230 by Boulos and 23 by Woods Electric.  NU, NGC, NAEC, NAESCO, NNECO, Mode 1 and NUEI have no employees.   

As a result of the March 2005 decision to exit the competitive wholesale and service businesses, 39 full-time positions have been eliminated.  It is expected that the November 2005 announcement to divest NU's remaining competitive businesses will necessitate further employee reductions.  See "Competitive Energy Businesses - Status of Divestitures."

Approximately 2,435 employees of CL&P, PSNH, WMECO, HWP, NGS and Yankee Gas are covered by 15 union agreements.  During 2005 and 2006 to date, six of seven contracts under negotiation have been ratified.  One Yankee Gas physical worker contract remains in the negotiation process.  In addition to the continued negotiation of this contract, NU expects to negotiate three PSNH labor contracts in the spring of 2006.

INTERNET INFORMATION

The NU system's Web site address is http://www.nu.com.  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 1A.

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" in Item 1, "Business," above.  NU's susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks.  These risk factors should be considered carefully in evaluating NU's  risk profile.

Risks Related to the Exit from the Competitive Businesses

On March 9, 2005, NU announced the decision to exit its wholesale marketing and energy services businesses, and on November 7, 2005, NU announced the decision to exit its retail marketing and competitive generation businesses, which constituted the remainder of NU's competitive business.  NU has disposed of a substantial part of its wholesale business, has sold two of its six services businesses and is in the process of selling the remainder, and is actively marketing its retail marketing business and competitive generation assets.

As of December 31, 2005, Select Energy had reached agreements to terminate or assign an estimated net 7.4 million megawatt-hours of wholesale electric sales obligations.  As of January 1, 2006, Select Energy still has an estimated 16.4 million megawatt-hours of wholesale electric sales obligations through the end of the last such obligation in 2013, all but 2.6 million megawatt-hours of which has been sourced.  However, sales volumes will likely be affected by weather, economic factors, and each contract's relative price compared with alternative sources of electricity.

The wholesale marketing business, until fully exited, will continue to present financial risk to NU from a variety of perspectives. These include earnings volatility around Select Energy's portfolio of contracts, which will be accounted for almost entirely on a mark-to-market basis until settled or exited.  NU recorded after tax losses associated with this portfolio during 2005 of $278.9 million, including $39.6 million in the fourth quarter of 2005.  NU may incur additional material charges to divest the remainder of the portfolio.  Two large remaining wholesale contracts expiring in 2007 and 2013, respectively, pose an additional level of risk due to the possibility that Select Energy may have to serve much higher levels of load than were previously anticipated.  NU recorded  pre-tax charges totaling approximately $53 million in the fourth quarter for changes in the estimates of the load forecasts related to these contracts.

In addition, the cost to exit several wholesale contracts was significantly more than Select Energy's mark-to-market, which was somewhat offset by several buyouts of municipal contracts at prices better than Select Energy's marks.  During the third quarter of 2005, Select Energy entered into a transaction under which it agreed to pay approximately $20 million in excess of its mark-to-market price to assign a number of its long-dated New England contracts to a third party.  In December 2005, Select Energy transferred the balance of its sales and purchase obligations in New England to a third party and  recognized a pre-tax loss in the fourth quarter of 2005 of $11.8 million compared to the September 30, 2005 mark-to-market.  Select Energy continues to have discussions regarding settlement of its remaining wholesale portfolio obligations.  Future contract settlements could also be at amounts higher than NU's mark-to-market amounts.  

The financial reliability of Select Energy's counterparties and its ability to manage its wholesale marketing portfolio of contracts and assets within acceptable risk parameters will be of material importance to Select Energy until these contracts are divested.  The net fair value position of the wholesale portfolio at December 31, 2005 was a net liability of $230.1 million, all which has been reflected in 2005 results.

NU's decision to exit the retail marketing and generation businesses could have material negative financial implications in 2006, depending on the outcome of a number of factors, including the resolution of certain accounting issues related to impairment of assets, recognition of closure or exit costs, recognition of losses in settling energy contracts, recognition of losses of the portfolio of retail contracts, and how the disposition of those businesses is accomplished.

Exiting from Select Energy's retail and remaining wholesale obligations could have an adverse impact on NU's liquidity, although any negative effect will be mitigated by the sale of the competitive generating assets.  The book value of NU's competitive generating assets was approximately $825 million at December 31, 2005.  NU's equity investment in its combined wholesale, retail and generation businesses is approximately $57 million at December 31, 2005.  Should NU fail to realize this equity amount on sale of these businesses after payment or assumption of all related debt, NU could incur further charges.  

To date, most of Select Energy's contract terminations have been on terms where Select Energy settled with its counterparty for a sum of money and obtained a full release from further liability on the contract.  One significant contract settlement was, and future contract terminations may be, negotiated on terms whereby Select Energy's obligations are assigned or transferred to a credit-worthy third party, but a release from Select Energy's customer is not obtained.  In such circumstances, Select Energy or another NU company will be liable to the customer should the third party default.  Any such contingent liabilities could remain open for extended periods of time.

NU currently expects, but cannot assure, that it will achieve the complete exit from its competitive businesses by the end of 2006.

Risks Related to NU Enterprises’ Wholesale and Retail Marketing and Competitive Generation Businesses

A significant portion of Select Energy's competitive energy marketing activities has been providing electricity to full requirements customers, which are primarily regulated local distribution companies (LDC) and commercial and industrial retail customers.  Under the terms of full requirements contracts, Select Energy is required to provide a percentage of the LDC's electricity requirements at all times.  The volumes sold under these contracts vary based on the usage of the LDC's retail electric customers, and usage is dependent upon factors outside of Select Energy's control, such as unanticipated migration or inflow of customers.  The varying sales volumes could be different than the supply volumes that Select Energy expected to utilize, either from its owned limited generation or from electricity purchase contracts, to serve the full requirements contracts.  Differences between actual sales volumes and supply volumes can require Select Energy to purchase additional electricity or sell excess electricity, both of which are subject to market conditions such as weather, plant availability, transmission congestion, and potentially volatile price fluctuations that can impact prices and, in turn, Select Energy's margins.

Until Select Energy disposes of its retail electric and gas marketing business, it will be subject to a number of ongoing risks which are similar, though of a lesser magnitude, to those of the wholesale marketing business.  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.  Extreme price volatility in the third quarter was responsible for a decline in new business in both the retail gas and electric sectors, and could impact this segment should price volatility recur.  This factor may affect Select Energy's ability to dispose of this business in accordance with its present expectations.

The competitive generation business is also subject to certain risks.  The future values of locational installed capacity credits which may become available to the owners of generation in the New England market in the future have not been finally determined and are subject to regulatory decision-making over which NU has no control.  

Risks Related to Liquidity and Collateral Calls

NU's senior unsecured debt ratings by Moody's Investors Service and Standard & Poor's, Inc. are currently Baa2 and BBB-, respectively, with stable outlooks.  Were either of these ratings to decline to non-investment grade level, Select Energy could be asked to provide, as of December 31, 2005, approximately $407 million of collateral or letters of credit to unaffiliated counterparties and $96 million to several independent system operators and unaffiliated local distribution companies and LDCs under agreements largely guaranteed by NU.  In addition, at December 31, 2005, Select Energy could have been requested to provide $12.7 million of collateral under certain contracts which counterparties have not required to date.  While NU's credit facilities are in amounts that would be adequate to meet calls at that level, NU's ability to meet any future calls would depend on its liquidity and access to bank lines and the capital markets at such time.

Risks Related to the Need for Future Financings

NU expects to obtain the liquidity needed to fund the exit from its remaining wholesale and retail marketing businesses through bank borrowings and a portion of the proceeds from the December 2005 sale of its common shares.  While NU is reasonably confident these funds will be available on a timely basis and on reasonable terms, failure to obtain such financing could delay NU's ability to exit the competitive businesses and constrain its ability to finance regulated capital projects.  In addition, any ratings downgrade of its operating company securities ratings could negatively impact the cost or availability of capital to such companies.

Risks Associated With the Transmission Operations of NU's Utility Subsidiaries

NU, primarily through its subsidiary CL&P, has undertaken a substantial transmission capital investment program over the past several years and expects to invest approximately $2.3 billion in regulated electric transmission infrastructure from 2006 through 2010.  Included in this amount is approximately $1.3 billion for costs associated with construction of two Connecticut 345 kV transmission lines from Middletown to Norwalk and Bethel to Norwalk; 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.  Recoverability of all such investments in rates may be subject to prudence review at the FERC at the time such projects are placed in service.  While NU believes that all such expenses have been prudently incurred, NU cannot predict the outcome of future reviews should they occur.

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.

Risks Associated with the Distribution Operations of NU's Utility Subsidiaries

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 that any given 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.  Recent increases in fuel and energy prices could lead to consumer or regulatory resistance to prompt recovery of such costs.

The energy requirements for PSNH are currently met primarily through PSNH's generation resources or long-term fixed price contracts.  The remaining energy needs are met through spot market or bilateral energy purchases.  Unplanned forced outages can increase the level of energy purchases needed by PSNH and therefore increase the market risk associated with procuring the necessary amount of energy to meet requirements.  PSNH recovers these costs through its stranded cost recovery charge proceedings, subject to a prudence review.

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 a civil lawsuit between Consolidated Edison, Inc. (Con Edison) and NU relating to the parties’ October 13, 1999 Agreement and Plan of Merger.

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.  In particular, more stringent regulation of carbon dioxide and mercury emissions have been proposed in various New England states.  Compliance with these requirements requires the NU system 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 may increase in the future.  An increase in such costs, unless promptly recovered, could have an adverse impact on NU's business and results of operations, financial position and cash flows.  For further information, see Item 1, "Business - Other Regulatory and Environmental Matters - Environmental Regulation."

The NU system's failure to comply with environmental laws and regulations, even if due to factors beyond its control or reinterpretations of existing requirements, could also increase costs.  

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

Severe Weather Conditions May Negatively Impact Results

Severe weather, such as ice and snow storms, hurricanes and other natural disasters, may cause outages and property damage which may require NU to incur additional costs that are generally not insured and that may not be recoverable from customers.  The cost of repairing damage to NU's operating subsidiaries' facilities and the potential disruption of their operations due to storms, natural disasters

or other catastrophic events could be substantial.  The effect of the failure of NU's facilities to operate as planned would be particularly burdensome during a peak demand period, such as during the hot summer months.  

Volatility in Electric and Gas Rates May Adversely Impact Sales

The nation's economy has been affected by the recent significant increases in energy prices, particularly fossil fuels.  The impact of these increases may lead to a decline in electricity and gas sales in NU's service territory.  Such a decline without an adjustment in rates would reduce NU's revenues and limit future growth prospects.  

Item 1B.

Unresolved Staff Comments

NU does not have any unresolved SEC staff comments.  

Item 2.

Properties

Transmission and Distribution System

At December 31, 2005, NU owned 312 transmission and 153 distribution substations that had an aggregate transformer capacity of 26,901,736 kilovoltamperes (kVa) and 1,531,166 kVa, respectively; 3,085 circuit miles of overhead transmission lines ranging from 69 kilovolt (kV) to 345 kV, and 215 cable miles of underground transmission lines ranging from 69 kV to 138 kV; 34,456 pole miles of overhead and 2,573 conduit bank miles of underground distribution lines; and 453,901 line transformers in service with an aggregate capacity of 20,342,000 kVa.

Electric Generating Plants

As of December 31, 2005, the NU system's electric generating plants were as follows:  

*Claimed capability represents winter ratings as of December 31, 2005.

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 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.  However, Public Act 05-01, "An Act Concerning Energy Independence," allows CL&P to own up to 200 MW of peaking facilities if the DPUC determines that such facilities will be more cost effective than other options for mitigating FMCCs and LICAP costs.  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 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.  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 no to distribute electricity at retail in Holyoke and surrounding towns unless other sellers can legally compete with HG&E and to amend the charters of HWP & HP&E to reflect that limitation.

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.

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 directly and from its predecessors in interest 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 Litigation

On March 5, 2001, Consolidated Edison, Inc. (Con Edison) advised NU that it was unwilling to close its merger with NU on the terms set forth in the parties' 1999 merger agreement (the Merger Agreement).  On March 12, 2001, NU filed suit against Con Edison seeking damages in excess of $1 billion.

On May 11, 2001, Con Edison filed an amended complaint seeking damages for breach of contract, fraudulent inducement and negligent misrepresentation in an unspecified amount, but which Con Edison's Chief Financial Officer has testified is at least $314 million.  NU disputes both Con Edison's entitlement to any damages as well as its method of computing its alleged damages.

The companies completed discovery in the litigation and submitted cross motions for summary judgment.  The court denied Con Edison's motion in its entirety, leaving intact NU's claim for breach of the Merger Agreement, and partially granted NU's motion for summary judgment by eliminating Con Edison's claims against NU for fraud and negligent misrepresentation.

In July 2003, an intervener in this litigation made the claim that NU shareholders at March 5, 2001 were entitled to damages from Con Edison, if any, and not current NU shareholders.  NU's cross-claim for summary judgment dismissing this assertion was denied in May 2004, and NU appealed to the United States Court of Appeals for the Second Circuit.

On October 12, 2005, the United State Court of Appeals for the Second Circuit issued a decision concluding that NU shareholders had no right to sue Con Edison for its alleged breach of the Merger Agreement.  As a result, the Second Circuit did not reach the second issue presented for review which was whether the right to pursue recovery of the $1 billion merger premium belongs to NU shareholders who held shares at the time of the breach or those who hold shares if and when a judgment is rendered against Con Edison.  NU filed for rehearing and suggested an en banc review on  October 26, 2005.  By order dated January 3, 2006, NU's request for rehearing was denied.  The ruling leaves intact the remaining claims between NU and Con Edison for breach of contract, which include NU's claim for recovery of costs and expenses of approximately $32 million and CEI's claim for damages of "at least $314 million."  NU senior management is currently considering whether to seek certiorari review by the U.S. Supreme Court.  A petition for certiorari may be filed on or before April 1, 2006.

A status conference was held in the U.S. District Court on February 7, 2006 to discuss next steps with respect to the remaining (non-shareholder) claims between the two companies.  A scheduling order is expected to follow.

 It is not possible to predict either the outcome of this matter or its ultimate effect on NU.

2.

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 alleged 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 sought monetary damages and a declaratory judgment.    

Select Energy filed an Answer to the complaint, denying any liability.  It 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 were consolidated on the complex litigation docket in Connecticut Superior Court and NU commenced discovery.  PSEG Power Connecticut LLC 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.  

On December 30, 2005 the case was settled and all claims and counterclaims have been withdrawn by all parties (i.e. Select, NU and PSEG Power Connecticut LLC) to the lawsuit.

3.

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 charges 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.  Discovery has concluded and the case is expected to go to trial in May 2006.

4.

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.

On September 18, 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 letter of credit (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 a counterclaim 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.  The parties subsequently reached a settlement in principle of their claims; however, MGT has since requested the court to place the case back on the trial calendar.  The parties are currently awaiting a scheduling order from the court.

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, and at present is withholding approximately $28 million.  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 approximately $29.6 million of 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.

5.

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.

On February 16, 2005, the U.S. District Court for the Southern District of Texas (the court to which the case was transferred after Hawkins removed it from the Connecticut Superior Court to Federal Court) entered an order dismissing the apportionment complaint (including the claims against NU, NUSCO and CL&P) with prejudice and remanding the case to the Waterbury Superior Court.  Subsequently, Hawkins appealed the February 16, 2005 order to the U. S. District Court of Appeals for the Fifth Circuit, where the appeal is pending.

6.

CYAPC Decommissioning Dispute

A.

Bechtel Power Corporation (Bechtel) Litigation

On June 14, 2003, CYAPC terminated 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.

In June 2003, Bechtel filed a complaint against CYAPC in Connecticut Superior Court.  Bechtel's complaint asserted 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.  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.

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.  On January 30, 2006, the court ruled that Bechtel could attach CYAPC's property up to the amount of $7.9 million and its shareholder equity in the amount of $41.7 million plus earned interest.

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, which offer was rejected by Bechtel.  Had one of the parties subsequently won the case in an amount equal to or greater than its offer, the court would have added 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.  

On March 7, 2006, CYAPC and Bechtel executed a settlement agreement terminating the court litigation.  Bechtel has agreed to pay CYAPC $15 million and withdraw from the FERC proceeding referred to below, and CYAPC will withdraw its termination of the contract for default and deem it terminated by agreement.

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.

The FERC administrative law judge conducted hearings on the reasonableness of the decommissioning rates in the spring of 2005.  The DPUC argued that CYAPC's imprudent management of the decommissioning project while Bechtel was the contractor resulted in schedule delays and costs increases and recommended a disallowance in the range of approximately $225 to $234 million.  Bechtel claimed that it was impossible for it to fulfill its contract obligations, CYAPC was not justified in terminating its contract and CYAPC's approach to the remaining decommissioning work was faulty.  The FERC trial staff argued that CYAPC should have used a lower gross domestic product (GDP) escalation rate in calculating the level of decommissioning charges and that use of such rate would reduce charges by $36 million.  In post trial briefs, the FERC trial staff also claimed that CYAPC's actions were imprudent and increases in decommissioning charges should be disallowed.

In an initial decision rendered on November 22, 2005, the FERC trial judge found no imprudence on CYAPC's part, and thus there was no basis for a rate disallowance.  However, the trial judge agreed with the FERC trial staff's lower GDP escalator for calculating the decommissioning rate increase.  Briefs addressing these issues are due in January and February 2006 and a final FERC order is expected later in 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.

7.

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 various New England states..  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.  Ground-breaking for the project took place on October 15, 2004.  The NHPUC's orders approving the Northern Wood Power Project were appealed to the New Hampshire Supreme Court by four existing wood-fired generating plants.  On April 4, 2005, the Supreme Court rejected the appeal and affirmed the NHPUC's approval Order.  The project is expected to commence commercial operation in the second half of 2006.  

8.

Enron Bankruptcy Claim

CL&P has a pending rejection damages claim against Enron Power Marketing, Inc. (EPMI) in the U. S. Bankruptcy Court for the Southern District of New York in the amount of $42.9 million.  The claimed damages result from the rejection of the December 22, 2000 electricity purchase agreement between EPMI and CL&P.  The Connecticut Resource Recovery Authority- related claim was objected to by EPMI and CL&P has filed its response.  An amended scheduling and discovery order was entered on December 14, 2005 providing that experts and documents must be disclosed over the next few months.  A status conference is scheduled for June 1, 2006.

Rulings by the bankruptcy judge on similar claims by different creditors of Enron and its subsidiaries may adversely affect the value of CL&P's $42.9 million rejection damages claim.  Management cannot predict the outcome of this litigation or its impact on CL&P.

9.

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 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.

10.

Other Legal Proceedings

The following sections of Item 1, "Business" discuss additional legal proceedings: See "Regulated Electric Operations," and "Regulated Gas Operations" for information about various state restructuring and rate proceedings, civil lawsuits related thereto, 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 nuclear waste; and "Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality requirements, toxic substances and hazardous waste, EMF, licensing of hydroelectric projects, and other matters.  In addition, see Item 1A, "Risk Factors" for general information about several significant risks.

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.

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, 2005.

As of January 31, 2006, there were 53,183 common shareholders of NU on record.  As of the same date, there were a total of 1,996,864 common shares issued, including 175,006,183 unallocated Employee Stock Ownership Plan (ESOP) shares held in the ESOP trust.

On February 14, 2006, the NU Board of Trustees approved the payment of 17.5 cent per share dividend, payable on March 31, 2006, to shareholders of record as of March 1, 2006.  

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 April 12, 2005, the NU Board of Trustees approved the payment of a 16.25 cent per share dividend, payable on June 30, 2005, to shareholders of record as of June 1, 2005.

On May 10, 2005, the NU Board of Trustees approved the payment of a 17.5 cent per share dividend, payable on September 30, 2005, to shareholders of record as of September 1, 2005.

On October 11, 2005, the NU Board of Trustees approved the payment of a 17.5 cent per share dividend, payable on December 30, 2005, to shareholders of record as of December 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.

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 the "Notes to Consolidated Financial Statements," within NU's 2005 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.

During 2005 and 2004, CL&P approved and paid $53.8 million and $47.1 million of common stock dividends to NU.

During 2005 and 2004, PSNH approved and paid $42.4 million and $27.2 million of common stock dividends, respectively, to NU.

During 2005 and 2004, WMECO approved and paid approximately $7.7 million and $6.5 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 2005 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 2005 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 2005 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 2005 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 2005 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 2005 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 2005 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 2005 Annual Report, which information is incorporated herein by reference.

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

Market Risk Information

The merchant energy business utilizes the sensitivity analysis methodology to disclose quantitative information for its commodity price risks (including where applicable capacity and ancillary components).  Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from market risk-sensitive instruments over a selected time period due to one or more hypothetical changes in commodity price components, or other similar price changes.  Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity components, contract prices and market prices represented by each derivative contract. For swaps, forward contracts and options, fair value reflects 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 - Retail Marketing Portfolio:  When conducting sensitivity analyses of the change in the fair value of Select Energy's retail marketing portfolio, which would result from a hypothetical change in the future market price of electricity and natural gas, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity and natural gas, 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.

Select Energy has determined a hypothetical change in the fair value for its retail marketing portfolio, which includes cash flow and fair value hedges and electricity and natural gas contracts, assuming a 10 percent change in forward market prices.  At December 31,

2005, a 10 percent increase in market price would have resulted in a pre-tax decrease in fair value of $30 million ($18 million after-tax) and a 10 percent decrease would have resulted in a pre-tax increase in fair value of $30.1 million ($18 million after-tax).

The impact of a change in electricity and natural gas prices on Select Energy's retail marketing portfolio at December 31, 2005, is not necessarily representative of the results that will be realized when these contracts are physically delivered.  Most contracts in the retail marketing portfolio are accounted for at delivery, and changes in fair value are not expected to impact earnings.  

NU Enterprises - Generation Portfolio:  When conducting sensitivity analyses of the change in the fair value of merchant energy's generation portfolio, which would result from a hypothetical change in the future market price of electricity, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments.  The merchant energy generation portfolio is comprised of primarily third party derivative generation related sales contracts (third party generation contracts) and physical generation from NGC and HWP (physical generation).  In most instances, market prices and volatility are determined from quoted prices.  Models are used for periods beyond 2009.  

A hypothetical change in the fair value for third party generation contracts was determined assuming a 10 percent change in forward market prices.  At December 31, 2005, a 10 percent increase in market price would have resulted in a pre-tax decrease in fair value of $13.9 million ($8.3 million after-tax) and a 10 percent decrease would have resulted in a pre-tax increase in fair value of $13.9 million ($8.3 million after-tax).  These transactions are accounted for at fair value, and changes in market prices impact earnings.  

A hypothetical change in the fair value for the physical generation was determined assuming a 10 percent change in forward market prices.  At December 31, 2005, a 10 percent increase in market price would have resulted in a pre-tax increase in fair value of $166.4 million ($99.8 million after-tax) and a 10 percent decrease would have resulted in a pre-tax decrease in fair value of $166.4 million ($99.8 million after-tax).  Physical generation is accounted for at delivery, and changes in fair value are not expected to impact earnings.

The impact of a change in electricity prices on merchant energy's generation portfolio at December 31, 2005, is not necessarily representative of the results that will be realized when these contracts are physically delivered or electricity is generated.  

NU Enterprises - Wholesale Portfolio:  When conducting sensitivity analyses of the change in the fair value of Select Energy's wholesale portfolio, which would result from a hypothetical change in the future market price of electricity, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments.

A hypothetical change in the fair value of the wholesale portfolio was determined assuming a 10 percent change in forward market prices . At December 31, 2005, Select Energy has calculated the market price resulting from a 10 percent change in forward market prices of those contracts.  A 10 percent increase would have resulted as a pre-tax decrease in fair value of $21.3 million ($12.8 million after-tax) and a 10 percent decrease would have resulted in a pre-tax increase in fair value of $20.2 million ($12.1 million after-tax).

The impact of a change in electricity and natural gas prices on Select Energy's wholesale transactions at December 31, 2005 are not necessarily representative of the results that will be realized when these contracts are physically delivered.  These transactions are accounted for at fair value, and changes in market prices impact earnings.

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, 2005, approximately 87 percent (79 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 $4 million.  At December 31, 2005, 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, 2005 and December 31, 2004, Select Energy maintained collateral balances from counterparties of $28.9 million and $57.7 million, respectively.  These amounts are included in counterparty deposits on the accompanying consolidated balance sheets.  Select Energy also has collateral balances deposited with counterparties of $103.8 million and $46.3 million at December 31, 2005 and December 31, 2004, 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.

NU has formed a Risk and Capital Committee comprised of senior NU officers, which reports to the Chief Executive Officer, to review the risks of large capital projects.  NU has also enlisted external engineering firms as agents on large projects providing engineering, procurement and construction management services and is conducting competitive bids on large components of all major projects.

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."

Item 8.

Financial Statements and Supplementary Data

NU.  Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of (Loss)/Income," "Consolidated Statements of Comprehensive (Loss)/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 2005 Annual Report to Shareholders, which information is incorporated herein by reference.

CL&P.  Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "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 2005 Annual Report, which information is incorporated herein by reference.

PSNH.  Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "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 2005 Annual Report, which information is incorporated herein by reference.

WMECO.  Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "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 2005 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 Northeast Utilities and subsidiaries (NU) and of other sections of NU's 2005 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 were effective as of December 31, 2005.

Deloitte & Touche LLP has issued an attestation report on management's assessment of internal controls over financial reporting.

NU, CL&P, PSNH and WMECO undertook separate evaluations 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 the companies' principal executive officers and principal financial officer, as of the end of the period covered by this Annual Report on Form 10-K.  The principal executive officers and principal financial officer have concluded, based on their review, that the companies' disclosure controls and procedures are effective 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 officers 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, 2005 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 this item at December 31, 2005, as this information has been previously disclosed in applicable reports on Form 8-K during the fourth quarter of 2005.

Part III

Item 10.

Directors and Executive Officers of the Registrants

The information in Item 10 is provided as of March 10, 2006 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 24, 2006, 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

SVP,  GC

Lawrence E. De Simone

P

Cheryl W. Grisé (1)

EVP

David R. McHale  (2)

SVP, CFO

Leon J. Olivier (3)

EVP

Charles W. Shivery

CHB, P, CEO, T

John P. Stack

VP, C

CL&P

         Name          

Positions  Held 

Gregory B. Butler (4)

SVP, GC

Cheryl W. Grisé (1)

CEO, D

David R. McHale (2)

SVP, CFO

Raymond P. Necci (5)

P, COO, D

Leon J. Olivier (3)

OTH, D

Charles W. Shivery

OTH

John P. Stack

VP, C

PSNH

         Name          

Positions  Held 

Gregory B. Butler (4)

SVP, GC

Cheryl W. Grisé (1)

CEO, D

Gary A. Long

P, COO, D

David R. McHale (2)

SVP, CFO, D

Leon J. Olivier (3)

OTH, D

Charles W. Shivery

OTH

John P. Stack

VP, C

WMECO

        Name          

Positions  Held 

Gregory B. Butler (4)

SVP, GC

Cheryl W. Grisé (1)

CEO, D

David R. McHale (2)

SVP, CFO, D

Leon J. Olivier (3)

OTH, D

Rodney O. Powell

P, COO, D

Charles W. Shivery

OTH

John P. Stack

VP, C

(1)

Served as President - Utility Group of NU until December 1, 2005, when she was elected Executive Vice President of NU.

(2)

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

(3)

Served as President-Transmission Group of NU effective January 17, 2005 until December 1, 2005 when he was elected Executive Vice President of NU.  Elected Director of WMECO & PSNH on January 17, 2005.  

(4)

Elected Senior Vice President and General Counsel of CL&P, WMECO and PSNH, effective March 9, 2006.

(5)

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.

          Name          

Age

Business Experience During Past Five Years

Gregory B. Butler

48

Senior Vice President and General Counsel of NU since December 1, 2005 and of CL&P, PSNH and WMECO since March 9, 2006, and a Director of Northeast Utilities Foundation, Inc. since December 1, 2002; previously Senior Vice President, Secretary and General Counsel of NU from August 31, 2003 to December 1, 2005; 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

58

President-Competitive Group of NU and President of NU Enterprises, Inc., since October 25, 2004, and Chairman, President and Chief Executive Officer 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.

Cheryl W. Grisé (*)

53

Executive Vice President of NU since December 1, 2005,  Chief Executive Officer of CL&P, PSNH and WMECO since September 10, 2002, a Director of CL&P since May 1, 2001, of PSNH since May 14, 2001 and of WMECO since June 2001, and a Director of Northeast Utilities Foundation, Inc. since September 23, 1998; previously President - Utility Group of NU from May 2001 to December 1, 2005; 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.

Gary A. Long (**)

54

President and Chief Operating Officer and a Director of PSNH since July 1, 2000; previously Senior Vice President 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

45

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 from July 1998 to December 31, 2004.

Raymond P. Necci

54

President and Chief Operating Officer and a Director of CL&P since January 17, 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

57

Executive Vice President of NU since December 1, 2005, a Director of WMECO and PSNH since January 17, 2005 and a Director of CL&P since September 2001; previously, President - Transmission Group of NU from January 17, 2005 to December 1, 2005. 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

53

President and Chief Operating Officer  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 (***)

60

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  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.  

John P. Stack (****)

47

Vice President - Accounting and Controller of NU, CL&P, WMECO and PSNH since January 2002. Previously Executive Director - Corporate Accounting and Taxes from  1998 to January 2002.

 (*)

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.

(****)

Mr. Stack is on the Board of the Connecticut Hospice and Chairman of its Audit and Finance Committee.

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) and a Standards of Business Conduct which is applicable to all Directors, officers, employees, contractors and agents of the Company.  The Code of Ethics and the Standards of Business Conduct have both been posted on Northeast Utilities’ web site and are 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 and the Standards of Business Conduct are also available to any shareholder without charge upon written request mailed to:

Ms. Kerry J. Kuhlman

Vice President and Secretary

Northeast Utilities Service Company

P.O. Box 270

Hartford, CT  06141

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 24, 2006, 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 for the last three years received by the Chief Executive Officer and the next four highest paid executive officers in 2005 (collectively, the named executive officers) of each of CL&P, PSNH, and WMECO in accordance with rules of the Securities and Exchange Commission (SEC):

Notes:

(1)

"Other Annual Compensation" in 2005 for Mr. Olivier includes $105,966 of supplemental pension payments under his previous employment agreement with Northeast Nuclear Energy Company, a subsidiary of NU.  "Other Annual Compensation" for all 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, 2005, 214,734 common shares, with an aggregate value of $4,228,093.  The aggregate restricted share holdings by each of the individuals named in the table and the value thereof, at December 31, 2005, were 95,776 common shares ($1,885,823) for Mr. Shivery; 62,073 common shares ($1,222,216) for Mrs. Grisé 18,421 common shares ($362,708) for Mr. Olivier; 25,434 common shares ($500,793) for Mr. Butler; and 13,030 common shares ($256,553) for Mr. McHale.  Each of the individuals was awarded restricted share units as long term incentive compensation during 2005, which vest over three years, with 50 percent payable at vesting and 50 percent payable four years after vesting; with the exception of restricted share units awarded to Mr. Shivery which vest over three years and are payable at retirement.  Dividends on restricted share units are reinvested and additional shares added as a result of reinvestment are vested and paid on the same schedule. Each restricted share unit represents the right to one common share of Northeast Utilities,  In addition, Mr. Shivery was awarded 25,000 restricted shares in 2004 upon his appointment as Chairman, President and CEO; these shares vest over four years and dividends are paid out during the vesting period.  In 2003, Messrs. Shivery, Olivier, Butler and McHale and Ms. Grisé 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 percent of the 2003 annual incentive payout for Mr. Shivery 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 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 2005 consists of employer matching contributions under the Northeast Utilities Service Company 401K Plan, generally available to all eligible employees ($6,300 for each named executive officer), matching contributions under the Deferred Compensation Plan for Executives (Mr. Shivery - $18,900, Mrs. Grisé -$9,240  and, Mr. Olivier - $5,630, and dividends on restricted stock (Mr. Shivery - $17,908, Mrs. Grisé - $7,757, Mr. Olivier - $1,874, Mr. Butler - $2,626 and Mr. McHale - $1,526).

(4)

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

(5)

Mrs. Grisé served as President - Utility Group of NU until December 1, 2005, when she was elected Executive Vice President of NU.

(6)

Mr. Olivier served as President of CL&P through January 17, 2005 when he was elected President - Transmission Group and then elected Executive Vice President of NU on December 1, 2005.

(7)

Mr. Butler was elected Senior Vice President and General Counsel of CL&P, PSNH and WMECO on March 9, 2006.

(8)

Mr. McHale was elected Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO on January 1, 2005.

LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR

Grants of three-year performance cash units were made during 2005 under the Northeast Utilities Incentive Plan to the Company's officers.  Payments will be made in cash following the close of the performance period.  Payments at the threshold, target, and maximum levels will be determined based on cumulative net income, average return on equity, average credit rating, and total shareholder return relative to thirteen utility companies, over the performance period. In the event of retirement before age 65, grants are prorated based on time in the performance period, their value is determined based on performance through the end of the performance period and the amounts are paid out at the end of the performance period. In the event of retirement after age 65, grants made prior to the calendar year of retirement are fully vested and grants made during the calendar year of retirement are prorated based on time in the performance period. The value of the grants is determined based on performance through the end of the performance period and the amounts are paid at the end of the performance period.  In the event of death, disability, or a Change of Control, as defined, grants are prorated based on time in the performance period, their value is set at target and the amounts are immediately paid out.  In the event of a Termination Upon a Change of Control, as defined, grants are fully vested, their value is set at target and the amounts are immediately paid out.       

Grants in 2005 to the named executive officers were as follows:

PENSION BENEFITS

The tables on the following pages show the estimated annual retirement benefits that would be payable to a named executive officer 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 (either at the 50 percent level or the 60 percent level) 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 each named executive officer, 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 awards under the executive incentive plans and deferred compensation (as earned) as "compensation" under the plan (See Table I below).  The target benefit under the Supplemental Plan 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).  On February 1, 2005, the Supplemental Plan was amended to change the formula for calculating the target benefit under the plan. Under the Supplemental Plan, as amended, the formula for calculating the target benefit for officers who were eligible for the target benefit before February 1, 2005, uses an amount equal to 60 percent of the officer's Final Average Compensation, as defined (See Table II below).  The formula for calculating the target benefit under the Supplemental Plan for officers who become eligible for the target benefit on or after February 1, 2005 uses an amount equal to 50 percent of the participant's Final Average Compensation (See Table III below). Each of the named executive officers is eligible for the target benefit based on 60 percent of compensation, with the exception of Mr. McHale, who became eligible for the target benefit on February 1, 2005 and thus is eligible for the target based on 50 percent of compensation, and Mr. Olivier, who is eligible solely for the make-whole benefit and is not eligible for the target benefit.  Mr. Olivier also has a special retirement pursuant to his employment arrangement (see below).

In addition, Mr. Shivery's employment agreement provides for a special retirement benefit consisting of an amount equal to the difference between 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 using an early commencement reduction factor of two percent per year for each year Mr. Shivery's age at commencement is under age 65, if better than the factors then in use under the Retirement Plan, and benefits otherwise payable from the Retirement Plan and the Supplemental Plan.  

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. Under this arrangement, 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. If the conditions described above are not met, then Mr. Olivier would be eligible for the make-whole benefit under the Supplemental Plan

TABLE I

ANNUAL BENEFIT FOR OFFICERS ELIGIBLE

 FOR MAKE-WHOLE BENEFIT

TABLE II

ANNUAL BENEFIT FOR OFFICERS ELIGIBLE  FOR

 MAKE WHOLE PLUS 60 PERCENT TARGET BENEFIT

TABLE III

ANNUAL BENEFIT FOR OFFICERS ELIGIBLE FOR

MAKE-WHOLE PLUS 50 PERCENT TARGET BENEFIT

The make-whole and target benefits presented in the tables above are based on a straight life annuity with a 33 1/3 percent and 50 percent, respectively surviving spouse benefit beginning at age 65 and do not take into account any additional 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 target annual value of long-term incentive compensation for 2001.  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 2005 for Mr. Shivery, Mrs. Grisé, Mr. Butler, and Mr. McHale for the target benefit was $1,475,166, $1,050,439, $613,583 and $428,730, respectively, and the compensation covered by the Supplemental Plan for Mr. Olivier for the make-whole benefit was $754,401.

As of December 31, 2005, the named executive officers participating in the Supplemental Plan had attained the following years of credited service for purposes of the Supplemental Plan: Mr. Shivery - 3, Mr. Olivier - 6, Mrs. Grisé - 25, Mr. Butler - 9, and Mr. McHale -24.

EMPLOYMENT AGREEMENTS, TERMINATION OF EMPLOYMENT AND CHANGE IN CONTROL ARRANGEMENTS

NUSCO has entered into employment agreements with Messrs. Shivery, Olivier, Butler and McHale and Mrs. Grisé. In addition, Mr. Olivier participates in the Special Severance Program for Officers of Northeast Utilities System Companies providing for benefits upon termination connected with a Change of Control, while other named executive officers have Change of Control benefits pursuant to the terms of the employment agreements..  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 agreement with Ms. Grisé was supplemented during 2001 to provide for special deferred compensation of  $500,000, which payment was vested and paid in even installments (adjusted to reflect investment performance) on June 28, 2002, 2003 and 2004.

Mr. Olivier's agreement provides for specified initial salary, restricted shares, and stock options, and retirement and other benefits.

The employment agreements, other than that with Mr. Olivier, 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 (60 days’ notice in the case of Mr. Shivery and Mr. McHale) 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.  Where termination of employment occurs for "cause," the agreements for Messrs. Shivery, Butler and McHale and for Mrs. Grisé provide that the supplemental retirement benefit will not be due except for the Make-Whole Benefit.  Absent "cause," the Company may remove the officer from his or her position on sixty days’ prior written notice (except in the case of Mr. Shivery and Mr. McHale, where no notice period is required), 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 at target level, specified employee welfare and pension benefits, and vesting of specified long-term incentive compensation.  

These employment agreements, other than that for Mr. Olivier, contain Change of Control provisions providing benefits upon any termination of employment (for reasons other than disability, death, retirement at or after age 65 or "cause") following a Change of Control , as defined, between (a) the earlier of (i) the date shareholders approve a Change of Control transaction or (ii) a Change of Control transaction occurs and (b) the earlier of (i) the date, if any, on which the Board of Trustees abandons the transaction or (ii) the date two years following the Change of Control.  Under these provisions,  if the officer signs a release of all claims against the Company, the officer will be entitled to certain payments, including two years’ of annual base salary plus annual incentive payments at target level for each year plus an additional year's base salary plus annual incentive payment at target level, for compliance with a covenant not to compete, along with specified employee welfare and pension benefits, and vesting of stock appreciation rights, options and restricted stock. Mr. Olivier is eligible for benefits on termination following Change of Control in accordance with the Special Severance Program, providing payment equal to two years’ annual base salary plus annual incentive payment at target level. Each  named executive officers, other than Mr. Olivier, will also receive additional benefits under the Supplemental Plan including eligibility for the Make-Whole Benefit and the Target Benefit, regardless of the executive's eligibility for early retirement under the Retirement Plan.  The named executive officers are also eligible for more favorable actuarial reductions for early commencement of retirement benefits than otherwise provided under the terms of the Retirement Plan.  A termination of employment preceding the actual date of the Change of Control may be subject to the same treatment s provided above only with specific approval by the Board of Trustees.

To the extent that the sum of benefits payable upon termination following Change of Control comprises an "excess parachute payment" under the Internal Revenue Code for any of the named executive officers, each of the named executive officers will also receive a gross-up payment offsetting the additional excise tax imposed as a result of the "excess parachute payment," and Federal, state and local taxes on such excise tax.   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).  

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 24, 2006, 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 percent of the outstanding common stock of registrants CL&P, PSNH, and WMECO.  The following table sets forth, as of February 28, 2006, 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 29,024 shares that could be acquired by Mr. Shivery pursuant to currently exercisable options, 1,500 shares which Mr. Shivery owns jointly with his wife with whom he shares voting and dispositive power, and 16,390 shares as to which Mr. Shivery has sole voting and no dispositive power.

(2)

As of February 28, 2006, 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 171,228 shares that could be acquired by Mrs. Grisé pursuant to currently exercisable options, 5,746 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.

(4)

Includes 19,900 shares that could be acquired by Mr. Olivier pursuant to currently exercisable options and 1,388 shares as to which Mr. Olivier has sole voting and no dispositive power.  

(5)

Includes 29,800 shares that could be acquired by Mr. Butler pursuant to currently exercisable options, 12,680 shares held jointly by Mr. Butler with his wife, with whom he shares voting and dispositive power, and 1,945 shares as to which Mr. Butler has sole voting but no dispositive power.

(6)

Includes 18,501 shares that could have been acquired by Mr. McHale pursuant to currently exercisable options and 1,130 shares as to which Mr. McHale 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, 7,379,357 shares were available for issuance as of December 31, 2005.  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, 6,517,239 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 24, 2006, 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 24, 2006, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

CL&P, PSNH, WMECO

None of CL&P, PSNH and WMECO are subject to the audit committee requirements of the Securities and Exchange Commission, the national securities exchanges or the national securities associations.  CL&P, PSNH and WMECO 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 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, PSNH, and WMECO: 

Fees Paid to Principal Auditor

The Company's principal auditor was paid fees aggregating $3,535,700 and $ 2,930,455 for the years ended December 31, 2005 and 2004, 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, 2005 and 2004 totaled $3,309,000 and $2,679,300, 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 fees also included audits of internal controls over financial reporting as of December 31, 2005 and 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, 2005 and 2004 totaled $148,000 and $174,950, 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, 2005 and 2004 totaled $55,000 and $54,965, 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, 2005 and 2004 for services other than the services described above totaled $23,700 and $21,240, respectively, primarily related to tax return software licensing.   

The Audit Committee pre-approves all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed for the Company by its independent auditors, subject to the de minimis exceptions for non-audit services described in Section 10A(i)(1)(B) of the Securities Exchange Act of 1934, which are approved by the Audit Committee prior to the completion of the audit.  The Audit Committee may form and delegate authority to subcommittees consisting of one or more members when appropriate, including the authority to grant pre-approvals of audit and permitted non-audit services, provided that decisions of such subcommittee to grant pre-approvals are presented to the full Audit Committee at its next scheduled meeting. No services were provided which were not pre-approved.

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.

Part IV

Item 15.

Exhibits and Financial Statement Schedules

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.

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.