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

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

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

Regional and System Coordination

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

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

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

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

Transmission Access and FERC Regulatory Changes

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

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

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

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

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

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

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

Rates - General

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

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

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

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

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

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

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

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

Connecticut Retail Rates

CL&P – Rate Matters

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

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

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

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

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

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

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

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

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

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

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

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

CL&P – Transmission Projects

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

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

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

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

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

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

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Yankee Gas

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

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

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

Massachusetts Retail Rates

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

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

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

New Hampshire Retail Rates

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

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

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

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

COMPETITIVE SYSTEM BUSINESSES

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

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

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

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

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Retail and Wholesale Marketing

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

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

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

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

Retail Marketing

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

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

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

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

Wholesale Marketing

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

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

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

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

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

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

Electric Generation

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

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

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

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

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

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Competitive Energy Subsidiaries’ Market And Other Risks

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

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

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

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

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

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

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

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

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

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

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

Energy Management Services

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

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

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

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

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

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

Telecommunications

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

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

REGULATED GAS OPERATIONS

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

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

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

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

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

FINANCING PROGRAM

2004 Financings

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

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

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

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

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

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

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

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

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

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

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

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