The Connecticut Light and Power Company (CNLTP) 10-K 2004 FY Annual report

2004 Annual Report

The Connecticut Light and Power Company

Index

Contents

Page

Management's Discussion and Analysis of Financial

  Condition and Results of Operations

1

Report of Independent Registered Public Accounting Firm

15

Consolidated Balance Sheets

16-17

Consolidated Statements of Income

18

Consolidated Statements of Comprehensive Income

18

Consolidated Statements of Common Stockholder's Equity

19

Consolidated Statements of Cash Flows

20

Notes to Consolidated Financial Statements

21

Consolidated Quarterly Financial Data (Unaudited)

37

Selected Consolidated Financial Data (Unaudited)

37

Consolidated Statistics (Unaudited)

38

Bondholder Information

Back Cover

This Page Intentionally Left Blank

Management’s Discussion and Analysis

Financial Condition and Business Analysis

Executive Summary

The following items in this executive summary are explained in more detail in this annual report.

Results:

·

The Connecticut Light and Power Company (CL&P or the company) reported earnings of $88 million in 2004 compared with earnings of $68.9 million in 2003 and $85.6 million in 2002.

Regulatory Items:

CL&P resolved a number of outstanding regulatory issues, providing the company with more ratemaking certainty than it has had in a number of years.  Among the most important items were:

·

On August 19, 2004, a Connecticut Superior Court dismissed the City of Norwalk's appeal of the Connecticut Siting Council’s (CSC) approval of a 345 kilovolt (kV) transmission line between Bethel, Connecticut and Norwalk, Connecticut.

·

On June 28, 2004, the Federal Energy Regulatory Commission (FERC) approved a settlement agreement to resolve the dispute over the implementation of Standard Market Design (SMD) in Connecticut.  Under the settlement, CL&P returned to its customers and suppliers, including affiliate Select Energy, Inc. (Select Energy), approximately $158 million of revenues collected from customers in 2003 and early 2004.

·

The Connecticut Department of Public Utility Control (DPUC) issued a final decision on August 4, 2004 on CL&P's petition for reconsideration of the DPUC's December 2003 rate order.  The decision had a positive earnings impact of $6.9 million in 2004.

·

On August 1, 2003, CL&P filed with the DPUC to establish transitional standard offer (TSO) rates equal to December 31, 1996 total rate levels.  On December 19, 2003, the DPUC issued a final decision setting the average TSO rate at $0.1076 per kilowatt-hour (kWh) effective January 1, 2004.

·

As a result of higher supply charges, higher federally mandated congestion charges (FMCC) and a $25.1 million distribution rate increase approved by the DPUC in CL&P's rate case, on November 24, 2004, CL&P requested the DPUC to increase its TSO rate for 2005.  On December 22, 2004, the DPUC approved a 10.4 percent rate increase effective January 1, 2005 and allowed for the recovery of the remainder of the requested increase through existing and new refunds and overrecoveries.

·

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.

·

On February 1, 2005, CL&P filed for approval for a 1.6 percent increase to TSO rates ($29.2 million) to collect additional FMCC from customers 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 prior to final approval.

Liquidity:

·

During 2004, CL&P issued a total of $280 million of fixed-rate bonds with maturities of 10 years to 30 years.  The debt was issued primarily to repay short-term and reduce long-term debt.

·

CL&P’s capital expenditures totaled $370.8 million in 2004, compared with $323.1 million in 2003 and $262.6 million in 2002.  The increase resulted from increased spending on new transmission projects.  CL&P projects capital expenditures of approximately $410 million in 2005.

·

CL&P’s net cash flows from operations totaled $229.2 million in 2004, compared with $417.5 million in 2003 and $407.6 million in 2002.  

Overview

CL&P is a wholly owned subsidiary of Northeast Utilities (NU).  NU’s other subsidiaries include Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), Yankee Energy System, Inc., North Atlantic Energy Corporation, Select Energy, Northeast Generation Company, Northeast Generation Services Company, and Select Energy Services, Inc.  

CL&P earned, before preferred dividends, $88 million in 2004, compared with $68.9 million in 2003 and $85.6 million in 2002.  CL&P’s improved earnings resulted primarily from a retail rate increase that took effect January 1, 2004.  These higher retail rates were offset by higher operating expenses, lower pension income and a higher effective tax rate.  CL&P also benefited from the final decision on the reconsideration of its rate case,

which had a positive after-tax impact of $6.9 million in 2004.  In 2003, after-tax write-offs of approximately $5 million were recorded based on the DPUC's December 2003 rate case order.  The higher effective tax rate was due to higher reversal of prior flow-through depreciation and other adjustments to tax expense totaling a negative $3.2 million recorded in the third quarter of 2004 as opposed to a positive $5.5 million recorded in 2003.

Included in CL&P’s earnings are the results of the transmission business.  CL&P’s transmission business earnings were $19.8 million in 2004 as compared to $17.1 million in 2003.  CL&P’s transmission business earnings in 2004 are higher than 2003 primarily due to higher revenues resulting from the implementation of a FERC approved formula rate resulting in increased rates and $88 million of transmission projects that were placed in service.  This forward-looking formula rate allows CL&P to place capital investments in rates immediately upon being placed in service.  The formula rate took effect on October 28, 2003.

CL&P’s revenues for 2004 increased to $2.8 billion from $2.7 billion in 2003 due to higher transmission and distribution revenues as a result of higher rates due to the implementation of the FERC approved formula rate and higher FMCC revenues.

Future Outlook

Management projects CL&P earnings to increase in 2005, compared with 2004 primarily due to rate increases that will go into effect in 2005.  Higher capital expenditures to meet customer service and reliability requirements is also expected to increase earnings, as long as CL&P can recover a return on its additional investments in a timely manner.  These costs will be partially offset by higher pension costs expected in 2005.

Strategic Overview

CL&P has identified significant investment requirements and expects to invest more than $2.4 billion in regulated electric infrastructure from 2005 through 2009.   

Based on current projections, management expects that the need to invest heavily in infrastructure to meet reliability requirements and customer growth will cause CL&P’s distribution rate base to rise from $1.2 billion in 2004 to nearly $2 billion by the end of 2009.  Based on currently projected expenditures and capital project completion dates, management expects that the same factors will increase CL&P’s transmission rate base from approximately $300 million in 2004 to approximately $1.4 billion by the end of 2009.

Liquidity

Cash flows from operations decreased by $188.3 million from $417.5 million in 2003 to $229.2 million in 2004.  The decrease in year over year operating cash flows is due to regulatory (refunds)/over-recoveries primarily due to lower Competitive Transition Assessment (CTA) and Generation Service Charge (GSC) collections in 2004 as CL&P refunds amounts to its ratepayers for past overcollections or uses those amounts to recover current costs.  These refunds are also the primary reason for the positive change in year over year deferred income taxes, which has increased operating cash flows as refunded amounts were currently deducted for tax purposes.  The change in lower current taxes paid because of income taxes also benefited cash flows from operations in 2004 due to bonus tax depreciation on newly completed plant assets.  

Capital expenditures described herein are cash capital expenditures and exclude cost of removal, allowance for funds used during construction (AFUDC) and the capitalized portion of pension income.  CL&P’s capital expenditures totaled $370.8 million in 2004, compared with $323.1 million in 2003 and $262.6 million in 2002.  The increase in capital expenditures was primarily the result of higher transmission capital expenditures, which totaled $128.1 million in 2004, compared with $63.5 million in 2003 and $39.1 million in 2002.  The company projects capital expenditures of approximately $2.4 billion over the five-year period from 2005 through 2009, including approximately $420 million in 2005.  Capital spending projections are highly dependent on regulatory approval of major projects, particularly transmission investments.

Management projects that CL&P will need approximately $2.8 billion from 2005 through 2009 to meet its capital expenditure requirements, dividends, and other cash requirements.  CL&P expects to fund approximately half of this need through operating cash flows with the remainder expected to be funded through external financings.  

To maintain a capital structure that includes approximately 55 percent of total debt at CL&P, NU continues to infuse common equity.  NU parent made a total of $88 million of common equity contributions to CL&P in 2004.

The significant capital requirements at CL&P were one reason that the credit rating outlooks on its securities were lowered in 2004.  Standard & Poor’s (S&P) reduced the outlook on the CL&P securities it rates to "negative" from "stable."  Fitch Ratings changed the outlook on CL&P debt to "negative" in January 2005.  In February 2005, Moody's Investors Service (Moody's) reduced by one level the ratings of CL&P.  The ratings changes will result in modest increases in future borrowing costs for CL&P on its revolving credit agreement.  The changes are not expected to have a material impact on borrowing costs when CL&P seeks long-term financing to support its capital investment plans.  All ratings of CL&P securities remain investment grade.  As a result, those downgrades had no impact on the company's financial results.

On November 8, 2004, CL&P entered into a 5-year unsecured revolving credit facility, under which CL&P is able to borrow up to $200 million on a short-term basis.  CL&P had $15 million in borrowings outstanding under this credit facility at December 31, 2004.  For more information regarding this revolving credit facility, see Note 2, "Short-Term Debt" to the consolidated financial statements.

In addition to its revolving credit line, CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues.  At December 31, 2004, CL&P had sold accounts receivable totaling $90 million to that financial institution.  For more information regarding the sale of receivables, see Note 1L, "Summary of Significant Accounting Policies - Sale of Customer Receivables" to the consolidated financial statements.

On September 17, 2004, CL&P issued $150 million of 10-year first mortgage bonds at a fixed interest rate of 4.8 percent and also issued $130 million of 30-year first mortgage bonds at a fixed interest rate of 5.75 percent.  CL&P used the proceeds from these issuances to repay short-term and reduce long-term debt.

During 2004, as part of the approved SMD settlement agreement, CL&P paid $83 million to its suppliers, of which $40.5 million was paid to affiliate Select Energy, and refunded $75 million to its customers.  Of the combined payment and refund amount totaling $158 million, $124 million was funded from an escrow fund that was established during 2003 and 2004 as these SMD costs were being collected from customers.  Additionally, the DPUC ordered a refund of $88.5 million in CTA/Systems Benefits Charge (SBC) overcollections over a seven-month period beginning with October 2004 consumption.  The combination of the SMD and CTA/SBC refunds, when combined with CL&P’s proposed capital expenditures, will negatively impact CL&P’s liquidity.  However, CL&P expects no difficulty in meeting these additional cash requirements.

Under FERC policy, transmission owners may capitalize debt and equity costs during the construction period through AFUDC.  Debt costs capitalized offset interest expense with no impact on net income, while equity costs capitalized increase net income.  CL&P expects to fund its construction expenditures with approximately 45 percent equity and 55 percent debt.  

Nuclear Decommissioning and Plant Closure Costs

Connecticut Yankee Atomic Power Company (CYAPC) is currently in litigation with Bechtel Power Corporation (Bechtel) over the termination of its decommissioning contract.  On June 13, 2003, CYAPC gave notice of the termination of its contract with Bechtel for the decommissioning of its nuclear power plant.  CYAPC terminated the contract due to Bechtel's incomplete and untimely performance and refusal to perform the remaining decommissioning work.  Bechtel has departed the site, and the decommissioning responsibility has been transitioned to CYAPC, which has recommenced the decommissioning process.

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.  The revised estimate reflects the increases in the projected costs of spent fuel storage, and increased security and liability and property insurance costs, and the fact that CYAPC is now self-performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel in July 2003.  CL&P's share of CYAPC's increase in decommissioning and plant closure costs is approximately $136 million.  On July 1, 2004, CYAPC filed with the FERC for recovery of these increased costs.  In the filing, CYAPC sought to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginnin g on January 1, 2005.  On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005 subject to refund, and scheduled hearings for May 2005.  In total, CL&P's estimated remaining decommissioning and plant closure obligation for CYAPC is $217.3 million at December 31, 2004.

On June 10, 2004, the DPUC and Office of Consumer Counsel (OCC) filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred.  On August 30, 2004, the FERC denied this petition.  On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition.  On October 29, 2004, the FERC issued an order granting further consideration regarding the DPUC's and OCC's petition for reconsideration.  No hearing date has been established for this reconsideration.  

On February 22, 2005, the DPUC filed testimony with FERC.  In its filed testimony, the DPUC argues that approximately $215 million to $225 million of CYAPC’s requested increase is due to CYAPC’s imprudence in managing the decommissioning project while Bechtel was the contractor.  Therefore, the DPUC recommends a total disallowance of between $225 million to $234 million.  Hearings are scheduled to begin on June 1, 2005.  CL&P’s share of the DPUC’s recommended disallowance is between $78 million to $81 million.

On June 23, 2003, Bechtel filed a complaint against CYAPC asserting a number of claims and seeking a variety of remedies, including monetary and punitive damages and rescission of the contract.  Bechtel has since amended its complaint to add claims for wrongful termination.  On August 22, 2003, CYAPC filed its answer and counterclaims, including counts for breach of contract, negligent misrepresentation and breach of duty of good faith and fair dealing.  Discovery is currently underway, and a trial has been scheduled for May 2006.  

In the prejudgment remedy proceeding before the Connecticut Supreme Court (the Court), Bechtel sought garnishment of the CYAPC decommissioning trust and related payments.  In October 2004, Bechtel and CYAPC entered into an agreement under which Bechtel waived its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CYAPC's real property in Connecticut and the escrowing of $41.7 million the sponsors are scheduled to pay to CYAPC through June 30, 2007 with respect to CYAPC's common equity.  This stipulation is subject to approval of the Court and would not be implemented until the Court found that such assets were subject to attachment.  CYAPC has contested the attachability of such assets.  The DPUC is an intervener in this proceeding.  

Management cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of the increased CYAPC decommissioning costs.  Management believes that the costs have been prudently incurred and will ultimately be recovered from the customers of CL&P.  However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.  Management also cannot predict the timing and the outcome of the litigation with Bechtel.

CYAPC, Yankee Atomic Electric Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) (the Yankee Companies) filed litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Nuclear Waste Policy Act of 1982 (the Act).  Under the Act, the United States Department of Energy (DOE) was to begin removing spent nuclear fuel from the nuclear plants of YAEC, MYAPC and CYAPC no later than January 31, 1998 in return for payments by each company into the nuclear waste fund.  No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies' plants.  YAEC, MYAPC and CYAPC collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates.  The wholesale utility customers in turn collect these payments from their retail electric customers. &nbs p;The Yankee Companies' individual damage claims attributed to

the government's breach totaling $548 million are specific to each plant and include incremental storage, security, construction and other costs through 2010, which is the earliest date the DOE projects that it will begin removing nuclear fuel.  The YAEC damage claim is $191 million, the MYAPC claim is $160 million and the CYAPC claim is $197 million.

The DOE trial ended on August 31, 2004, and a verdict has not been reached.  The current Yankee Companies' rates do not include an amount for recovery of damages in this matter.  Management can predict neither the outcome of this matter nor its ultimate impact on CL&P.

Business Development and Capital Expenditures

In 2004, CL&P’s capital expenditures totaled $370.8 million, compared with depreciation of $119.3 million.  In 2003 and 2002, capital expenditures totaled $323.1 million and $262.6 million, respectively, compared with depreciation of $104.5 million and $98.4 million, respectively.  In 2005, capital expenditures are projected to total approximately $420 million, compared with projected depreciation of approximately $120 million.  The increasing level of capital expenditures is driven primarily by a need to improve the capacity and reliability of CL&P’s energy delivery system.  That increased level of capital expenditures, compared with depreciation levels, also is increasing the amount of plant in service and CL&P’s earnings base, provided CL&P achieves timely recovery of its investment.

In December 2003, the DPUC approved $900 million of distribution capital expenditures for CL&P from 2004 through 2007.  Those expenditures are intended to improve the reliability of the distribution system and to meet growth requirements on the distribution system.  In 2004, CL&P’s distribution capital expenditures totaled $242.7 million compared with $259.6 million in 2003 and $223.5 million in 2002.  In 2005, CL&P projects distribution capital expenditures of approximately $230 million.

CL&P’s transmission capital expenditures totaled $128.1 million in 2004, compared with $63.5 million in 2003 and $39.1 million in 2002.  In 2005, CL&P’s transmission capital expenditures are projected to total approximately $190 million.  The primary reason for the increase projected for 2005 is the expectation that construction will increase in the spring of 2005 on a new 21-mile, 345 kV transmission project between Bethel, Connecticut and Norwalk, Connecticut.  The CSC initially approved that project in July 2003.

On August 19, 2004, a Connecticut Superior Court judge dismissed an appeal by the City of Norwalk of the permit granted to CL&P by the CSC to construct a 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 customer 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 receiving permits from the towns and the Connecticut Department of Transportation.  The major line construction contracts were signed in early March 2005.  Management estimates a project completion date of December 2006.  At December 31, 2004, CL&P has capi talized $65 million of costs 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 the New England Independent System Operator (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 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 ch anges 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 being considered by the CSC to lower magnetic fields along the overhead portion of the proposed route would add between $70 million and $80 million to the estimated cost.  The CSC completed hearings on the proposal and the alternatives on February 17, 2005, and 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.

On October 1, 2004, CL&P and the Long Island Power Authority (LIPA) jointly filed plans with the Connecticut Department of Environmental Protection 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 on June 24, 2004.  This project is estimated to cost in the range of $114 million to $135 million with CL&P and LIPA each owning approximately 50 percent of the line.  The cost range reflects that vendor contracts have not yet been signed.  The project has received CSC approval, and federal and New York state approvals are expected in 2005.  Pending final approval, construction activities are scheduled to begin in the fall of 2006.  Management expects the line to be in service by the middle of 2008.  At December 31, 2004, CL&P has capitalized $7 milli on of costs related to this project.

In May 2004, CL&P applied to the CSC to construct two 115 kV 9-mile 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 of costs related to this project.

During 2004, CL&P placed in service $88 million of electric transmission projects.  These projects included $38 million for the upgrade of a transmission substation in Stamford, Connecticut that will allow additional electricity to be imported into southwest Connecticut.

Transmission Access and FERC Regulatory Changes

CL&P is a member of the New England Power Pool (NEPOOL) and, since 1997, has provided regional open access transmission service over its transmission system under the NEPOOL Open Access Transmission Tariff, which is administered by ISO-NE and local open access transmission service under the NU Companies Open Access Tariff No. 10, which the NU companies administer.

On October 31, 2003, ISO-NE, along with NU and six other New England transmission owning companies, filed a proposal with the FERC to create a Regional Transmission Organization (RTO) for New England in compliance with a 1999 FERC order calling on all transmission owners to voluntarily join RTOs (Order 2000).  The RTO is intended to strengthen the independent and efficient management of the region’s power system while ensuring that customers in New England continue to have highly reliable service and realize the benefits of a competitive wholesale energy market.  

In a separate filing made on November 4, 2003, the New England transmission owning companies requested, consistent with the FERC’s proposed 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 a 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.  

On November 3, 2004, the FERC issued an order that 1) determined that the New England transmission owners' methodology used to calculate the proposed ROE is appropriate, 2) clarified the application of the 0.5 percent incentive adder for joining a RTO for regional assets and reaffirmed the appropriateness of the 1.0 percent incentive adder for new investments; however, it left still unresolved the type of investments to which the 1.0 percent incentive adder should apply, and 3) 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 the conclusion of an ordered hearing, which commenced on January 25, 2005.  As part of the hearing procedures, the New England transmission owners submitted supplemental testimony supporting their ROE proposal on January 10, 2005 that, among other things, updated the ROE calculations submitted with the November filing.  The decision on the ROE incentive adders could result in a different ROE being utilized in the calculation of regional network service (RNS) tariffs than the ROE utilized in the calculation of local network service (LNS) tariffs.  An initial administrative law judge decision on these issues is expected in May 2005, and a final ruling regarding these issues is expected by the first quarter of 2006. & nbsp;

In January 2005, the New England transmission owners voted affirmatively to approve activation of the RTO, which occurred on February 1, 2005.  As of February 1, 2005, transmission rates were adjusted to reflect the ROEs proposed by the New England transmission owners in the original RTO filing (12.8 percent plus the requested 0.5 percent), subject to refund 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.

Regulatory Issues and Rate Matters

Transmission:  Wholesale transmission revenues are based on rates and formulas that are approved by the FERC.  Most of CL&P’s wholesale transmission revenues are collected through a combination of the RNS tariff and LNS tariff.  CL&P’s LNS tariff is reset on June 1st of each year to coincide with the change in RNS rates.  Additionally, CL&P’s LNS tariff provides for a true-up to actual costs which ensures that CL&P recovers its wholesale transmission revenue requirements, including the allowed ROE.   

On June 14, 2004, the transmission segment reached a settlement agreement with the parties to its rate case, which allows CL&P to implement formula-based rates as proposed with an allowed ROE of 11.0 percent.  On September 16, 2004, the FERC approved the settlement agreement.  The retroactive impact of the change in ROE from 11.75 percent to 11.0 percent reduced CL&P’s earnings by $0.7 million and $0.1 million, in 2004 and 2003, respectively.  Effective February 1, 2005, the 11.0 percent ROE was increased to the aforementioned 12.8 percent ROE.   

On February 1, 2005, consistent with its tariff, CL&P implemented an increase to its transmission tariff that is expected to increase 2005 revenues by approximately $3 million over 2004 transmission revenues.

A significant portion of CL&P's transmission business revenue is from charges to CL&P's electric distribution business.  CL&P recovers transmission charges through rates charged to its retail customers.  The 2004 rates set in the CL&P distribution rate case contained a level of transmission revenue sufficient to recover CL&P's 2004 transmission costs.  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.  CL&P currently does not have a transmission rate tracking mechanism that tracks transmission costs.

LICAP:   In March 2004, ISO-NE filed a proposal at the FERC to implement locational installed capacity (LICAP) requirements.  LICAP is an administratively determined electric generation asset 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 at the end of February 2005.  A FERC decision is anticipated in the fall of 2005.  Management cannot at this time predict the outcome of this FERC proceeding.

CL&P will incur LICAP charges.  Because southwest Connecticut is a constrained area with insufficient generation assets, CL&P could incur LICAP costs totaling several hundred million dollars.  These costs would be recovered from CL&P's customers through the FMCC mechanism.  

Public Act No. 03-135 and Rate Proceedings:  On June 25, 2003, the Governor of Connecticut signed into law Public Act No. 03-135 (the Act) which amended Connecticut's 1998 electric utility industry legislation.  The Act required CL&P to file a four-year transmission and distribution plan with the DPUC.  On December 17, 2003, the DPUC issued its final decision in the rate case.

CL&P filed a petition for reconsideration of certain items in the final decision on December 31, 2003.  The DPUC issued a final decision on the petition on August 4, 2004.  The final decision authorized CL&P to use existing CTA overrecoveries in lieu of an increase in rates to recover approximately $24 million, which is the net present value of the $32 million sought in the reconsideration.  The final decision had a 2004 positive pre-tax impact of $11.5 million ($6.9 million after-tax) on CL&P.  The remaining amount of $12.5 million is being amortized over four years beginning August 1, 2004 as an increase to revenues as the related costs to be recovered are incurred.  

Under the Act, CL&P is allowed to collect a fixed procurement fee of 0.50 mills per kWh from customers who purchase TSO service.  One mill is equal to one-tenth of a cent.  That fee can increase to 0.75 mills if CL&P outperforms certain regional benchmarks.  The fixed portion of the procurement fee amounted to approximately $12 million (approximately $7 million after-tax) for 2004.  On September 15, 2004, CL&P submitted to the DPUC its proposed methodology to calculate the variable portion (incentive portion) of the procurement fee.  On November 18, 2004, the DPUC suspended this proceeding and has not indicated when the schedule will be resumed.  The variable portion of the procurement fee has not yet been reflected in earnings.

Retail Transmission Rate Filing:  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 this deferral, CL&P’s application provides for an alternate proposal to increase its retail transmission rate to recover an additional $7.6 million on an annual basis, effective February 1, 2005.  Under this proposal the increase would equal $0.00031 per kWh, and would represent approximately a 0.2 percent increase in overall rates as of February 1, 2005.  Hearings in this docket have not been scheduled.

CTA and SBC Reconciliation:  The CTA allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and independent power producer (IPP) over market costs, while the SBC allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced worker protection costs.

On April 1, 2004, CL&P filed its 2003 CTA and SBC reconciliation with the DPUC, which compares CTA and SBC revenues to revenue requirements.  A final decision in the 2003 CTA and SBC docket was issued on August 4, 2004 and ordered a refund to customers of $88.5 million over a seven-month period beginning with October 2004 consumption.  

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 tax liability in CTA revenue requirements has been a reduction in revenue of ap proximately $19 million.

Application for Issuance of Long-Term Debt: On September 9, 2004, CL&P filed an application with the DPUC requesting approval to issue long-term debt in the amount of $600 million during the period February 1, 2005 to December 31, 2007.  Additionally, CL&P requested approval to enter into hedging transactions from time to time through December 31, 2007 in connection with any prospective or outstanding long-term debt in order to reduce the interest rate risk associated with the debt or debt issuances.  A final decision from the DPUC was issued on January 26, 2005.  The final decision approved CL&P's request to issue $600 million in long-term debt through December 31, 2007.  Additionally, the final decision approved CL&P's request to enter into hedging transactions in connection with any prospective or outstanding long-term debt in order to reduce the interest rate risk associate d with the debt or debt issuances.  CL&P plans to issue up to $200 million in long-term debt by the middle of 2005.

CL&P TSO Rates:  The vast majority of CL&P’s customers buy their energy through CL&P’s TSO, rather than buying energy directly from competitive suppliers.  On August 1, 2003, CL&P filed with the DPUC to establish TSO rates equal to December 31, 1996 total rate levels.  In October 2003, CL&P requested bids from wholesale energy marketers to supply its TSO requirements from 2004 through 2006.  Five wholesale marketers supplied CL&P’s TSO requirements in 2004, including Select Energy.  On December 19, 2003, the DPUC issued a final decision setting the average TSO rate of $0.1076 per kWh effective January 1, 2004.  In November 2004, CL&P requested bids from wholesale marketers to supply the TSO requirements in 2005 and 2006 that were not filled in the 2003 solicitation.  Due to higher energy prices, the bids received and accepted by CL& amp;P were significantly higher than those accepted in 2003.  As a result of the higher supply costs, higher FMCC and a $25.1 million distribution rate increase approved by the DPUC in CL&P's rate case, on November 24, 2004, CL&P requested the DPUC to increase its TSO rate by 16.7 percent in 2005.  On December 22, 2004, the DPUC approved the increase of 16.2 percent effective January 1, 2005, although the impact was partially offset by a continuation of the CTA refund.  The DPUC also ordered that projected 2004 and 2005 CTA overrecoveries and half of projected 2004 distribution overrecoveries be used to moderate increases for customers that otherwise would occur when the current CTA refund expires on May 1, 2005.  Overall, the final decision approved an increase to the January 2004 TSO rates of approximately 10.4 percent, including the effects of existing and new refunds and overrecoveries.  The DPUC denied requests by the Connecticut Attorney General and OCC to defer th e recovery of higher supplier costs into future years.  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.  Management believes that this appeal will not impact the DPUC's December 22, 2004 order.

Also, pursuant to state law, on December 19, 2003, the DPUC set CL&P’s TSO rates for January 1, 2004 through December 31, 2004 and confirmed that state law exempted FMCC, Energy Adjustment Clause (EAC) charges and certain other charges from the statutorily imposed rate cap.  The OCC filed appeals of this decision with 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.  Management believes that these appeals will not impact the TSO rates approved by the DPUC.

On February 1, 2005, CL&P filed for a 1.6 percent increase to rates ($29.2 million) to collect additional FMCC from customers effective May 1, 2005.  The increase is necessary to collect costs related to an additional 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 prior to final approval.

Off-Balance Sheet Arrangements

The CL&P Receivables Corporation (CRC) was incorporated on September 5, 1997, and is a wholly owned subsidiary of CL&P.  CRC has an arrangement with CL&P to purchase and has an arrangement with a highly rated financial institution under which CRC can sell up to $100 million of an undivided interest in accounts receivable and unbilled revenues.  At December 31, 2004 and 2003, CRC had sold an undivided interest in its accounts receivable and unbilled revenues of $90 million and $80 million, respectively, to that financial institution with limited recourse.

CRC was established for the sole purpose of selling CL&P's accounts receivable and unbilled revenues and is included in the consolidated  CL&P financial statements.  On July 7, 2004, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 6, 2005, and the termination date of the facility was extended to July 3, 2007.  Management plans to renew this agreement prior to its expiration.  CL&P’s continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables.

The transfer of receivables to the financial institution under this arrangement qualifies for sale treatment under Statement of Financial Accounting Standards (SFAS) No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement of SFAS No. 125."  Accordingly, the $90 million and $80 million outstanding under this facility are not reflected as debt or included in the consolidated financial statements at December 31, 2004 and 2003, respectively.  This off-balance sheet arrangement is not significant to CL&P’s liquidity or other benefits.  There are no known events, demands, commitments, trends, or uncertainties that will, or are reasonably likely to, result in the termination, or material reduction in the amount available to the company under this off-balance sheet arrangement.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, assumptions and at times difficult, subjective or complex judgments.  Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact the financial statements of CL&P.  Management communicates to and discusses with NU's Audit Committee of the Board of Trustees all critical accounting policies and estimates.  The following are the accounting policies and estimates that management believes are the most critical in nature.  

Presentation:  In accordance with current accounting pronouncements, CL&P's consolidated financial statements include all subsidiaries upon which control is maintained and all variable interest entities (VIE) for which CL&P is the primary beneficiary, as defined.  Determining whether the company is the primary beneficiary of a VIE is subjective and requires management's judgment.  There are certain variables taken into consideration to determine whether the company is considered the primary beneficiary to the VIE.  A change in any one of these variables could require the company to reconsider whether or not it is the primary beneficiary of the VIE.  All intercompany transactions between these subsidiaries are eliminated as part of the consolidation process.  

CL&P has less than 50 percent ownership interests in CYAPC, YAEC and MYAPC.  CL&P does not control these companies and does not consolidate them in its financial statements.  CL&P accounts for the investments in these companies using the equity method.  Under the equity method, CL&P records its ownership share of the earnings or losses at these companies.  Determining whether or not CL&P should apply the equity method of accounting for an investment requires management judgment.  

In December 2003, the Financial Accounting Standards Board (FASB) issued a revised version of FIN 46 (FIN 46R).  FIN 46R has resulted in fewer CL&P investments meeting the definition of a VIE.  FIN 46R was effective for CL&P for the first quarter of 2004 and did not have an impact on CL&P's consolidated financial statements.

Revenue Recognition:  CL&P retail revenues are based on rates approved by the DPUC.  These regulated rates are applied to customers' use of electricity to calculate a bill.  In general, rates can only be changed through formal proceedings with the DPUC.

The determination of the electricity sales to individual customers is based on the reading of meters, which occurs on a systematic basis throughout the month.  Billed revenues are based on these meter readings.  At the end of each month, amounts of electricity delivered to customers since the date of the last meter reading are estimated and an estimated amount of unbilled revenues is recorded.

CL&P utilizes regulatory commission approved tracking mechanisms to track the recovery of certain incurred costs.  The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.

Wholesale transmission revenues are based on rates and formulas that are approved by the FERC.  Most of CL&P’s wholesale transmission revenues are collected through a combination of the RNS tariff and CL&P's LNS tariff.  The RNS tariff, which is administered by ISO- NE, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities.  The LNS tariff, which was accepted by the FERC on October 22, 2003, provides for the recovery of CL&P's wholesale transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates.

Unbilled Revenues:  Unbilled revenues represent an estimate of electricity delivered to customers that has not been billed.  Unbilled revenues represent assets on the balance sheet that become accounts receivable in the following month as customers are billed.

The estimate of unbilled revenues is sensitive to numerous factors that can significantly impact the amount of revenues recorded.  Estimating the impact of these factors is complex and requires management's judgment.  The estimate of unbilled revenues is important to CL&P's consolidated financial statements as adjustments to that estimate could significantly impact operating revenues and earnings.  

CL&P currently estimates unbilled revenues monthly using the requirements method.  The requirements method utilizes the total monthly volume of electricity or gas delivered to the system and applies a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers.  The total estimated monthly sales amount less total monthly billed sales amount results in a monthly estimate of unbilled sales.  Unbilled revenues are estimated by applying an average rate to the estimate of unbilled sales.  The estimated DE factor can have a significant impact on estimated unbilled revenue amounts.

During 2004 the unbilled sales estimates for CL&P were tested using the cycle method.  The cycle method uses the billed sales from each meter reading cycle and an estimate of unbilled days in each month based on the meter reading schedule.  The cycle method is historically more accurate than the requirements method when used in a mostly weather-neutral month.  The cycle method testing was performed in the second and fourth quarters of 2004 but did not have a material impact on earnings.  

During 2003 the cycle method resulted in adjustments to the estimate of unbilled revenues that had a positive after-tax earnings impact of $7.2 million.

Derivative Accounting:  Effective January 1, 2001, CL&P adopted SFAS No. 133, as amended.  

Many of CL&P’s contracts for the purchase or sale of energy or energy-related products are derivatives.  The application of derivative accounting under SFAS No. 133, as amended, is complex and requires management judgment in the following respects: election and designation of the normal purchases and sale exception, identification of derivatives and embedded derivatives, identifying hedge relationships, assessing and measuring hedge ineffectiveness, and determining the fair value of derivatives.  All of these judgments, depending upon their timing and effect, can have a significant impact on CL&P’s consolidated net income.

The judgment applied in the election of the normal purchases and sale exception (and resulting accrual accounting) includes the conclusions that it is probable at the inception of the contract and throughout its term that it will result in physical delivery and that the quantities will be used or sold by the business over a reasonable period in the normal course of business.  If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting would be terminated and fair value accounting would be applied.  Cash flow hedge contracts that are designated as hedges for contracts for which the company has elected the normal purchases and sales exception can continue to be accounted for as cash flow hedges only if the normal exception for the hedged contract continues to be appropriate.  If the normal exception is terminated, then the hedge designat ion would be terminated at the same time.

In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amended existing derivative accounting guidance.  This new statement incorporates interpretations that were included in previous Derivative Implementation Group (DIG) guidance, clarifies certain conditions, and amends other existing pronouncements.  It was effective for contracts entered into or modified after June 30, 2003.  The adoption of SFAS No. 149 resulted in fair value accounting for certain CL&P contracts that are subject to unplanned netting and do not meet the definition of capacity contracts.  These non-trading derivative contracts are recorded at fair value at December 31, 2004 and 2003 as derivative assets and liabilities with offsetting amounts recorded as regulatory liabilities and assets because the contracts are part of providing regulated el ectric service.  

Emerging Issues Task Force (EITF) Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, and ‘Not Held for Trading Purposes’ as Defined in EITF Issue No. 02-3," was derived from EITF Issue No. 02-3, which requires net reporting in the income statement of energy trading activities.  Issue No. 03-11 addresses income statement classification of revenues related to derivatives that physically deliver and are not related to energy trading activities.  Prior to Issue No. 03-11, there was no specific accounting guidance that addressed the classification in the income statement of CL&P’s power supply contracts, many of which are non-trading derivatives.

On July 31, 2003, the EITF reached a consensus in Issue No. 03-11 that determining whether realized gains and losses on contracts that physically deliver and are not held for trading purposes should be reported on a net (sales and purchases both in expenses) or gross (sales in revenues and purchases in expenses) basis is a matter of judgment that depends on the relevant facts and circumstances.  The EITF indicated that existing accounting guidance should be considered and provided no new guidance in Issue No. 03-11.  In Issue No. 03-11, the EITF did not provide transition guidance, which management could have interpreted as becoming applicable on October 1, 2003 for revenues from that date forward.  However, during 2003 management applied its conclusion on net or gross reporting to all periods presented to enhance comparability.

CL&P reports the settlement of all short-term sales contracts that are part of procurement activities on a net basis in expenses.

On June 25, 2003, the DIG cleared Issue No. C-20, which addressed the meaning of "not clearly and closely related regarding contracts with a price adjustment feature" as it relates to the election of the normal purchase and sales exception to derivative accounting.  The implementation of this guidance was required for the fourth quarter of 2003 for CL&P.  The implementation of Issue No. C-20 resulted in CL&P recording the fair value of two existing power purchase contracts as derivatives, one as a derivative asset, and one as a derivative liability.  An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of stranded costs, and management believes that these costs will continue to be recovered or refunded in rates.

Regulatory Accounting:  The accounting policies of CL&P historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."  The transmission and distribution businesses of CL&P continue to be cost-of-service rate regulated, and management believes the application of SFAS No. 71 to that portion of those businesses continues to be appropriate.  

Management must reaffirm this conclusion at each balance sheet date.  If, as a result of a change in circumstances, it is determined that any portion of CL&P no longer meets the criteria of regulatory accounting under SFAS No.71, that portion of the company will have to discontinue regulatory accounting and write-off their regulatory assets and liabilities.  Such a write-off could have a material impact on CL&P's consolidated financial statements.

The application of SFAS No. 71 results in recording regulatory assets and liabilities.  Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates.  In some cases, CL&P records regulatory assets before approval for recovery has been received from the DPUC.  Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery.  Management bases its conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by the DPUC and the status of any potential new legislation.  Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.  

Management uses its best judgment when recording regulatory assets and liabilities; however, the DPUC can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on CL&P’s consolidated financial statements.  Management believes it is probable that CL&P will recover the regulatory assets that have been recorded.

Pension and Postretirement Benefits Other Than Pensions (PBOP):  CL&P participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular CL&P employees.  CL&P also participates in a postretirement benefit plan (PBOP Plan) to provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees.  For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions.  If these assumptions were changed, the resulting change in benefit obligations, fair values of plan assets, funded status and net periodic benefit credits or costs could have a material impact on CL&P's consolidated financial statements.

Results:  Pre-tax periodic pension income for the Pension Plan, excluding special termination benefits, totaled $14.3 million, $29.1 million and $50.6 million for the years ended December 31, 2004, 2003 and 2002, respectively.  The pension income amounts exclude one-time items recorded under SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits."

As a result of litigation with nineteen former employees, in April 2004, NU was ordered by the court to modify its retirement plan to include special retirement benefits for fifteen of these former employees retroactive to the dates of their retirement and provide increased future monthly benefit payments.  In the third quarter of 2004, NU withdrew its appeal of the court's ruling.  As a result, CL&P recorded $1.1 million in special termination benefits related to this litigation in 2004.

There were no settlements, curtailments or special termination benefits recorded in 2003.

Net SFAS No. 88 items associated with early termination programs and the sale of the Millstone and Seabrook nuclear units totaled $8.1 million in expense for the year ended December 31, 2002.  This amount was recorded as a regulatory liability for refund to customers.

The pre-tax net PBOP Plan cost, excluding special termination benefits, totaled $18.6 million, $16.6 million and $17.4 million for the years ended December 31, 2004, 2003 and 2002, respectively.  

Long-Term Rate of Return Assumptions:  In developing the expected long-term rate of return assumptions, CL&P evaluated input from actuaries and consultants, as well as long-term inflation assumptions and CL&P's historical 20-year compounded return of approximately 11 percent.  CL&P's expected long-term rates of return on assets is based on certain target asset allocation assumptions and expected long-term rates of return.  CL&P believes that 8.75 percent is a reasonable long-term rate of return on Pension Plan and PBOP Plan assets for 2004.  CL&P will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the appropriate assumptions as necessary.  The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long-term rates of return assumptions by asset category are as follows:

	At December 31,
	Pension Benefits		Postretirement Benefits
	2004 and 2003		2004 and 2003
	Target Asset	Assumed Rate of	Target Asset	Assumed Rate of
Asset Category	Allocation	Return	Allocation	Return
Equity securities:
United States	45%	9.25%	55%	9.25%
Non-United States	14%	9.25%	11%	9.25%
Emerging markets	3%	10.25%	2%	10.25%
Private	8%	14.25%	-	-
Debt Securities:   Fixed income	20%	5.50%	27%	5.50%
High yield fixed income	5%	7.50%	5%	7.50%
Real estate	5%	7.50%	-	-

The actual asset allocations at December 31, 2004 and 2003 approximated these target asset allocations.  CL&P regularly reviews the actual asset allocations and periodically rebalances the investments to the targeted asset allocations when appropriate.  For information regarding actual asset allocations, see Note 4, "Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.  

Actuarial Determination of Income and Expense:  CL&P bases the actuarial determination of Pension Plan and PBOP Plan income/expense on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets.  Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.  There will be no impact on the fair value of Pension Plan and PBOP Plan assets.

At December 31, 2004, the Pension Plan had cumulative unrecognized investment gains of $27.2 million, which will decrease pension expense over the next four years.  At December 31, 2004, the Pension Plan also had cumulative unrecognized actuarial losses of $157.2 million, which will increase pension expense over the expected future working lifetime of active Pension Plan participants, or approximately 13 years.  The combined total of unrecognized investment gains and actuarial losses at December 31, 2004 is a net unrecognized loss of $130 million.  These gains and losses impact the determination of pension expense and the actuarially determined prepaid pension amount recorded on the consolidated balance sheets but have no impact on expected Pension Plan funding.

At December 31, 2004, the PBOP Plan had cumulative unrecognized investment gains of $19.1 million, which will decrease PBOP Plan expense over the next four years.  At December 31, 2004, the PBOP Plan also had cumulative unrecognized actuarial losses of $85.6 million, which will increase PBOP Plan expense over the expected future working lifetime of active PBOP Plan participants, or approximately 13 years.  The combined total of unrecognized investment gains and actuarial losses at December 31, 2004 is a net unrecognized loss of $66.5 million.  These gains and losses impact the determination of PBOP Plan cost and the actuarially determined accrued PBOP Plan cost recorded on the consolidated balance sheets.

Discount Rate:  The discount rate that is utilized in determining future pension and PBOP obligations is based on a yield-curve approach where each cash flow related to the Pension or PBOP liability stream is discounted at an interest rate specifically applicable to the timing of the cash flow.  The yield curve is developed from the top quartile of AA rated Moody's and S&P's bonds without callable features outstanding at December 31, 2004.  This process calculates the present values of these cash flows and calculates the equivalent single discount rate that produces the same present value for future cash flows.  The discount rates determined on this basis are 6.00 percent for the Pension Plan and 5.50 percent for the PBOP Plan at December 31, 2004.  Discount rates used at December 31, 2003 were 6.25 percent for the Pension Plan and the PBOP Plan.

Expected Contribution and Forecasted Income/(Expense):  Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on Pension Plan assets of 8.75 percent, a discount rate of 6.00 percent and an expected rate of return on PBOP assets of 6.85 percent for health assets, net of tax and 8.75 percent for life assets and non-taxable health assets, a discount rate of 5.50 percent and various other assumptions, CL&P estimates that expected contributions to and forecasted expense for the Pension Plan and PBOP Plan will be as follows (in millions):

	Pension Plan		Postretirement Plan
Year	Expected  Contributions	Forecasted Expense/ (Income)	Expected Contributions	Forecasted Expense
2005	$ -	$  2.1	$22.1	$22.1
2006	$ -	$  3.0	$20.6	$20.6
2007	$ -	$(3.8)	$17.3	$17.3

Future actual pension and postretirement expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the plans and amounts capitalized.

Sensitivity Analysis:  The following represents the increase/(decrease) to the Pension Plan's and PBOP Plan's reported cost as a result of the change in the following assumptions by 50 basis points (in millions):

	At December 31,
	Pension Plan		Postretirement Plan
Assumption Change	2004	2003	2004	2003
Lower long-term    rate of return	$  4.7	$  4.9	$0.3	$0.3
Lower discount rate	$  5.1	$  4.9	0.4	$0.4
Lower compensation   increase	$(2.0)	$(2.0)	N/A	N/A

Plan Assets:  The market-related value of the Pension Plan assets has increased from $899.3 million at December 31, 2003 to $965.4 million at December 31, 2004.  The projected benefit obligation (PBO) for the Pension Plan has increased from $731.3 million at December 31, 2003 to $800.1 million at December 31, 2004.  These changes have decreased the funded status of the Pension Plan on a PBO basis from an overfunded position of $168 million at December 31, 2003 to an overfunded position of $165.4 million at December 31, 2004.  The PBO includes expectations of future employee compensation increases.  The accumulated benefit obligation (ABO) of the Pension Plan was approximately $269 million less than Pension Plan assets at December 31, 2004 and approximately $253 million less than Pension Plan assets at December 31, 2003.  The ABO is the obligation for employee service and compensa tion provided through December 31, 2004.  If the ABO exceeds Pension Plan assets at a future plan measurement date, CL&P will record an additional minimum liability.  CL&P has not made employer contributions since 1991.

The value of PBOP Plan assets has increased from $64.3 million at December 31, 2003 to $74.9 million at December 31, 2004.  The benefit obligation for the PBOP Plan has increased from $169.3 million at December 31, 2003 to $192.4 million at December 31, 2004.  These changes have increased the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $105 million at December 31, 2003 to

$117.5 million at December 31, 2004.  CL&P has made a contribution each year equal to the PBOP Plan’s postretirement benefit cost, excluding curtailments, settlements and special termination benefits.

Health Care Cost:  The health care cost trend assumption used to project increases in medical costs was 8 percent for 2004 and 9 percent for 2003, decreasing one percentage point per year to an ultimate rate of 5 percent in 2007.  The effect of increasing the health care cost trend by one percentage point would have increased 2004 service and interest cost components of the PBOP Plan cost by $0.4 million in 2004 and $0.3 million in 2003.

Income Taxes:  Income tax expense is calculated each year in each of the jurisdictions in which CL&P operates.  This process involves estimating CL&P's actual current tax exposures as well as assessing temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses for tax and book accounting purposes.  These differences result in deferred tax assets and liabilities, which are included in CL&P's consolidated balance sheets.  Adjustments made to income taxes could significantly affect CL&P's consolidated financial statements.  Management must also assess the likelihood that deferred tax assets will be recovered from future taxable income, and to the extent that recovery is not likely, a valuation allowance must be established.  Significant management judgment is required in determining income tax expense, deferred tax assets an d liabilities and valuation allowances.

CL&P accounts for deferred taxes under SFAS No. 109, "Accounting for Income Taxes."  For temporary differences recorded as deferred tax liabilities that will be recovered in rates in the future, CL&P has established a regulatory asset.  The regulatory asset amounted to $207.5 million and $140.9 million at December 31, 2004 and 2003, respectively.  Regulatory agencies in certain jurisdictions in which CL&P operates require the tax effect of specific temporary differences to be "flowed through" to utility customers.  Flow through treatment means that deferred tax expense is not recorded in the consolidated statements of income.  Instead, the tax effect of the temporary difference impacts both amounts for income tax expense currently included in customers’ rates and the company’s net income.  Flow through treatment can result in effective income tax r ates that are significantly different than expected income tax rates.  Recording deferred taxes on flow through items is required by SFAS No. 109, and the offset to the deferred tax amounts is the regulatory asset referred to above.  

A reconciliation from expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in Note 13, "Income Tax Expense," to the consolidated financial statements.

The estimates that are made by management in order to record income tax expense, accrued taxes and deferred taxes are compared each year to the actual tax amounts filed on CL&P’s income tax returns.  The income tax returns were filed in the fall of 2004 for the 2003 tax year, and CL&P recorded differences between income tax expense, accrued taxes and deferred taxes on its consolidated financial statements and the amounts that were on its income tax returns.  

Depreciation:  Depreciation expense is calculated based on an asset’s useful life, and judgment is involved when estimating the useful lives of certain assets.  A change in the estimated useful lives of these assets could have a material impact on CL&P's consolidated financial statements absent timely rate relief for CL&P’s assets.  

Accounting for Environmental Reserves:  Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated.  Adjustments made to environmental liabilities could have a significant effect on earnings.  The probabilistic model approach estimates the liability based on the most likely action plan from of a variety of available remediation options, ranging from no action to remedies ranging from establishing institutional controls to full site remediation and long-term monitoring.  The probabilistic model approach estimates the liabilities associated with each possible action plan based on findings through various phases of site assessments.  These estimates are based on currently available information from presently enacted state and federal environmental laws and regulat ions and several cost estimates from outside engineering and remediation contractors.  These amounts also take into consideration prior experience in remediating contaminated sites and data released by the United States Environmental Protection Agency and other organizations.

These estimates are subjective in nature partly because there are usually several different remediation options from which to choose when working on a specific site.  These estimates are subject to revisions in future periods based on actual costs or new information concerning either the level of contamination at the site or newly enacted laws and regulations.  The amounts recorded as environmental liabilities on the consolidated balance sheets represent management’s best estimate of the liability for environmental costs based on current site information from site assessments and remediation estimates.  These liabilities are estimated on an undiscounted basis.

CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism.  Accordingly, changes in CL&P's environmental reserves impact CL&P's earnings.

Capital expenditures related to environmental matters are expected to total approximately $7.9 million in aggregate for the years 2005 through 2009.

Asset Retirement Obligations:  CL&P adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," on January 1, 2003.  SFAS No. 143 requires that legal obligations associated with the retirement of property, plant and equipment be recorded as a liability on the balance sheet at fair value when incurred and when a reasonable estimate of the fair value can be made.  SFAS No. 143 defines an asset retirement obligation (ARO) as a legal obligation that is required to be settled due to an existing or enacted law, statute, ordinance, or a written or oral promise to remove an asset.  AROs may stem from environmental laws, state laws and regulations, easement agreements, building codes, contracts, franchise grants and agreements, oral promises made upon which third parties have relied, or the dismantlement, restoration, or reclamation of properties.

Upon adoption of SFAS No. 143, certain removal obligations were identified that management believes are AROs but either have not been incurred or are not material.  These removal obligations arise in the ordinary course of business or have a low probability of occurring.  The types of

obligations primarily relate to transmission and distribution lines and poles, telecommunication towers, transmission cables and certain FERC or state regulatory agency re-licensing issues.  There was no impact to CL&P's earnings upon adoption of SFAS No. 143; however, if there are changes in certain laws and regulations, orders, interpretations or contracts entered into by CL&P, there may be future AROs that need to be recorded.

On June 17, 2004, the FASB issued the proposed interpretation, "Accounting for Conditional Asset Retirement Obligations."  The proposed interpretation requires an entity to recognize a liability for the fair value of an ARO that is conditional on a future event if the liability’s fair value can be reasonably estimated and clarifies that there are no circumstances in which a law or regulation obligates an entity to perform retirement activities but then allows the entity to permanently avoid settling the obligation. If adopted in its current form, there may be an impact to CL&P for AROs that CL&P currently concludes have not been incurred (conditional obligations).  These conditional obligations may include utility poles and asbestos that, if removed or disturbed by construction or demolition, creates a disposal obligation.  Management is in the process of evaluating the impact of the inte rpretation on CL&P.

Under SFAS No. 71, regulated utilities, including CL&P, currently recover amounts in rates for future costs of removal of plant assets.  Future removals of assets do not represent legal obligations and are not AROs.  Historically, these amounts were included as a component of accumulated depreciation until spent.  At December 31, 2004 and 2003, these amounts totaling $144.3 million and $150 million, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.  

Special Purpose Entities:In addition to the special purpose entity that is described in the "Off-Balance Sheet Arrangements" section of this Management's Discussion and Analysis, during 2001, to facilitate the issuance of rate reduction certificates intended to finance certain stranded costs, CL&P established CL&P Funding LLC.  CL&P Funding LLC was created as part of a state-sponsored securitization program.  CL&P Funding LLC is restricted from engaging in non-related activities and is required to operate in a manner intended to reduce the likelihood that it would be included in CL&P’s bankruptcy estate if it ever became involved in a bankruptcy proceeding.  CL&P Funding LLC and the securitization amounts are consolidated in the accompanying consolidated financial statements.

For further information regarding the matters in this "Critical Accounting Policies and Estimates," section, see Note 1, "Summary of Significant Accounting Policies," Note 3, "Derivative Instruments," Note 4, "Pension Benefits and Postretirement Benefits Other Than Pensions," Note 13, "Income Tax Expense," and Note 6B, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements.

Other Matters

Commitments and Contingencies:  For further information regarding other commitments and contingencies, see Note 6, "Commitments and Contingencies," to the consolidated financial statements.

Contractual Obligations and Commercial Commitments:  Information regarding CL&P’s contractual obligations and commercial commitments at December 31, 2004 is summarized through 2009 and thereafter as follows:

(Millions of Dollars)	2005	2006	2007	2008	2009	Thereafter
Notes payable   to banks(a)	$ 15.0	$      -	$     -	$     -	$     -	$         -
Long-term debt(a)	-	-	-	-	-	843.7
Estimated interest   payments on     existing   long-term debt	49.0	49.0	49.0	49.0	49.0	812.4
Capital   leases (b) (c)	2.6	2.5	2.4	2.1	2.0	18.1
Operating   leases (c) (d)	20.6	19.4	18.1	14.4	7.3	31.3
Required funding   of other post-   retirement benefit   obligations	22.1	20.6	17.3	13.0	9.4	N/A
Long-term   contractual   arrangements(c) (d)	283.6	278.8	275.8	258.0	228.3	1,090.9
Totals	$392.9	$370.3	$362.6	$336.5	$296.0	$2,796.4

^(a)  Included in CL&P's debt agreements are usual and customary positive, negative and financial covenants.  Non-compliance with certain covenants, for example timely payment of principal and interest, may constitute an event of default, which could cause an acceleration of principal in the absence of receipt by the company of a waiver or amendment.  Such acceleration would change the obligations outlined in the table of contractual obligations and commercial commitments.  

^(b) The capital lease obligations include imputed interest of $15.6 million.

^(c) CL&P has no provisions in its capital or operating lease agreements or agreements related to its long-term contractual arrangements that couldtrigger a change in terms and conditions, such as acceleration of payment obligations.

^(d)  Amounts are not included on CL&P's consolidated balance sheets.

Rate reduction bond amounts are non-recourse to CL&P, have no required payments over the next five years and are not included in this table.  CL&P's standard offer service contracts and default service contracts also are not included in this table.  For further information regarding CL&P’s

contractual obligations and commercial commitments, see Note 2, "Short-Term Debt," Note 6D, "Commitments and Contingencies - Long-Term Contractual Arrangements," Note 8, "Leases" and Note 12 , "Long-Term Debt," to the consolidated financial statements.

Forward Looking Statements:  This discussion and analysis includes statements concerning CL&P's expectations, plans, objectives, future financial performance and other statements that are not historical facts.  These statements are "forward looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995.  In some cases the reader can identify these forward looking statements by words such as "estimate," "expect," "anticipate," "intend," "plan," "believe," "forecast," "should," "could," and similar expressions.  Forward looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in the forward looking statements.  Factors that may cause actual results to differ materially from those include d 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 commodity markets, effectiveness of our risk management policies and procedures, changes in accounting standards and financial reporting regulations, fluctuations in the value of electricity positions, changes in the ability to sell electricity positions, obtaining new contracts at anticipated volumes and margins, terrorist attacks on domestic energy facilities and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports to the Securities and Exchange Commission (SEC).  Management undertakes no obligation to update the information contained in any forward looking statements to reflect developments or circumstances occurring after the statement is made.

Web Site: Additional financial information is available through CL&P's web site at www.cl-p.com.

RESULTS OF OPERATIONS

The following table provides the variances in income statement line items for the consolidated statements of income included in this annual report for the past two years.  

Income Statement Variances	2004 over/(under) 2003		2003 over/(under) 2002
(Millions of Dollars)	Amount	Percent	Amount	Percent
Operating Revenues	$128	5%	$197	8 %
Operating Expenses:
Fuel, purchased and net interchange power	96	6	125	8
Other operation	54	14	79	26
Maintenance	8	11	(7)	(9)
Depreciation	15	14	6	6
Amortization	(82)	(77)	18	20
Amortization of rate reduction bonds	7	7	7	7
Taxes other than income taxes	1	-	5	4
Gain on sale of utility plant	-	-	16	100
Total operating expenses	99	4	249	11
Operating income	29	15	(52)	(21)
Interest expense, net	-	-	(10)	(9)
Other income, net	17	(a)	(17)	(79)
Income before income tax expense	46	53	(59)	(40)
Income tax expense	27	(a)	(42)	(70)
Net income	$19	28%	$  (17)	(20)%

(a) Percent greater than 100.  

Operating Revenues

Operating revenues increased $128 million in 2004, compared with the same period in 2003, due to higher distribution revenues ($112 million) and higher transmission revenues ($16 million).

The distribution revenue increase of $112 million is primarily due to non-earnings components of retail rates ($89 million).  The distribution and retail transmission components of CL&P’s rates which flows through to earnings increased $31 million, primarily due to the retail transmission rate increase effective in January 2004.  The non-earnings components increase of $89 million is primarily due to the pass through of energy supply costs ($168 million) and FMCC ($151 million), partially offset by the resolution of SMD cost recovery which was being collected from CL&P customers in 2003 and early 2004 and also partially refunded in late 2004 ($71 million), lower wholesale revenues due in part to the expiration of long-term contracts ($46 million), lower CL&P EAC revenue as a result of the end of EAC billings in 2003 ($44 million), lower system benefit cost recoveries ($31 million), lower transition cost recoveries ($21 million), and lower revenue to fund C&LM initiatives ($16 million).  Retail sales in 2004 were 0.1 percent higher than 2003.  

Transmission revenues were higher due to the October 2003 implementation of the transmission rate case approved at the FERC.

Operating revenues increased $197 million in 2003, primarily due to higher retail revenues ($144 million), and higher wholesale revenues ($51 million).  Retail revenues were higher primarily due to the collection of incremental locational marginal pricing (LMP) costs beginning in May 2003 ($72 million) net of amounts to be returned to customers and higher retail sales volumes ($72 million) which includes a positive adjustment in estimated unbilled revenue of approximately $39 million.  Retail kWh sales increased by 3.3 percent in 2003 with the adjustment to unbilled sales.  Wholesale revenues were higher primarily due to higher market prices in 2003.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $96 million in 2004, primarily due to an increase in the standard offer service supply costs ($152 million), partially offset by lower deferrals of fuel expense as a result of the lower levels of fuel and congestion costs ($53 million).

Fuel, purchased and net interchange power expense increased $125 million in 2003, primarily due to incremental LMP costs that were recovered from customers ($72 million) and higher standard offer purchases as a result of higher retail sales ($47 million).  

Other Operation

Other operation expenses increased $54 million in 2004, primarily due to higher RMR costs ($60 million) and other power pool related expenses recovered through the Federally Mandated Congestion Cost (FMCC) charge ($11 million), partially offset by lower C&LM expense ($22 million).

Other operation expenses increased $79 million in 2003, primarily due to higher administrative costs ($37 million) resulting from lower pension income, higher RMR related transmission costs ($30 million), higher C&LM expenses ($8 million) and higher distribution expenses ($5 million), partially offset by lower related nuclear expenses ($4 million) as a result of the final DPUC order regarding the CL&P Millstone use of proceeds docket in the first quarter of 2003.

Maintenance

Maintenance expenses increased $8 million in 2004 primarily due to the 2003 positive resolution of the CL&P Millstone use of proceeds docket ($4 million) and higher distribution maintenance expenses ($4 million).

Maintenance expenses decreased $7 million in 2003, primarily due to lower nuclear related expenses ($6 million) as a result of the final DPUC order regarding the CL&P Millstone use of proceeds docket in the first quarter of 2003.

Depreciation

Depreciation expense increased $15 million in 2004, primarily due to higher utility plant balances in 2004 resulting from plant additions and higher depreciation rates resulting from the distribution rate case decision effective in January 2004.

Depreciation expense increased $6 million in 2003, primarily due to higher utility plant balances in 2003 resulting from plant additions.

Amortization

Amortization expense decreased $82 million in 2004 primarily due to the lower amortization related to the recovery of system benefit and transition charges ($54 million), primarily due to the lower recovery of stranded costs resulting from the decrease in the system benefit and transition charge component of retail rates, and a decrease in amortization expense resulting from the amortization of GSC over-recoveries allowed in the distribution rate case decision effective in January 2004 ($29 million).

Amortization increased $18 million in 2003, primarily due to higher amortization related to the recovery of stranded costs ($73 million), partially offset by lower amortization of recoverable nuclear costs ($38 million), and amortization expense recorded in 2002 related to gain on the sale of CL&P’s ownership share in Seabrook ($16 million).

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $7 million in 2004 and increased $7 million in 2003, due to the repayment of a higher principal amount.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $1 million in 2004, primarily due to higher property taxes.

Taxes other than income taxes increased $5 million in 2003, primarily due to higher gross earnings taxes ($2 million), the recognition in 2002 of a Connecticut sales and use tax audit settlement ($7 million), partially offset by lower tax payments to the Town of Waterford in 2003 as compared to 2002 ($4 million).

Gain on Sale of Utility Plant

Gain on sale of utility plant decreased in 2003 due to the $16 million gain recorded in 2002 on the sale of CL&P’s ownership share in Seabrook versus no gain recorded in 2003.

Interest Expense, Net

Interest expense, net decreased $10 million in 2003 primarily due to lower interest on rate reduction bonds ($5 million) and other interest ($3 million).

Other Income, Net

Other income, net increased $17 million in 2004, primarily due to the recognition beginning in 2004 of a procurement fee approved in the TSO docket ($12 million), higher interest and dividend income ($3 million) and higher C&LM incentive income ($2 million).

Other income, net decreased $17 million in 2003, primarily due to lower interest and dividend income ($4 million), lower equity in earnings from the nuclear entitlements ($4 million), lower C&LM incentive income ($2 million), and higher charitable donations ($2 million).

Income Tax Expense

Income tax expense increased $27 million in 2004 due to higher income before tax expense, higher reversals of flow through depreciation and adjustments to tax expense as a result of the actual 2003 tax return amounts compared to the 2003 year end tax provision estimates.

Income tax expense decreased in 2003 primarily due to lower book taxable income.  For further information regarding income tax expense, see Note 13, "Income Tax Expense," to the consolidated financial statements.

Company Report    

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

The company has endeavored to establish a control environment that encourages the maintenance of high standards of conduct in all of its business activities.  Management is responsible for maintaining a system of internal controls over financial reporting, that is designed to provide reasonable assurance, at an appropriate cost-benefit relationship, to the company’s management and Board of Trustees of Northeast Utilities regarding the preparation of reliable, published financial statements.  The system is supported by an organization of trained management personnel, policies and procedures, and a comprehensive program of internal audits.  Through established programs, the company regularly communicates to its management employees their internal control responsibilities and obtains information regarding compliance with policies prohibiting conflicts of interest and policies segregating information between r egulated and unregulated subsidiary companies.  The company has standards of business conduct for all employees, as well as a code of ethics for senior financial officers.

The Audit Committee of the Board of Trustees of Northeast Utilities is composed entirely of independent trustees and includes two members that the Board of Trustees considers "audit committee financial experts."  The Audit Committee meets regularly with management, the internal auditors, and the independent auditors to review the activities of each and to discuss audit matters, financial reporting matters, and the system of internal controls over financial reporting.  The Audit Committee also meets periodically with the internal auditors and the independent auditors without management present.

Because of inherent limitations in any system of internal controls, errors or irregularities may occur and not be detected.  The company believes, however, that its system of internal controls over financial reporting and control environment provide reasonable assurance that its assets are safeguarded from loss or unauthorized use and that its financial records, which are the basis for the preparation of all financial statements, are reliable.  Additionally, management believes that its disclosure controls and procedures are in place and operating effectively.  Disclosure controls and procedures are designed to ensure that information included in reports such as this annual report is recorded, processed, summarized, and reported within the time periods required and that the information disclosed is accumulated and reviewed by management for discussion and approval.

Report of Independent Registered Public Accounting Firm    

To the Board of Directors of

The Connecticut Light and Power Company:

We have audited the accompanying consolidated balance sheets of The Connecticut Light and Power Company and subsidiaries (a Connecticut corporation and a wholly owned subsidiary of Northeast Utilities) (the "Company") as of December 31, 2004 and 2003, and the related consolidated statements of income, comprehensive income, common stockholder’s equity and cash flows for each of the three years in the period ended December 31, 2004.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of The Connecticut Light and Power Company and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

/s/

DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP

Hartford, Connecticut

March 16, 2005

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
At December 31,	2004	2003
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash	$                         5,608	$                         5,814
Restricted cash - LMP costs	-	93,630
Investments in securitizable assets	139,391	166,465
Receivables, less provision for uncollectible
accounts of $2,010 in 2004 and $21,790 in 2003	69,892	60,759
Accounts receivable from affiliated companies	66,386	73,986
Unbilled revenues	8,189	6,961
Taxes receivable	766	-
Materials and supplies, at average cost	33,213	31,583
Derivative assets - current	24,243	15,609
Prepayments and other	15,004	12,521
	362,692	467,328
Property, Plant and Equipment:
Electric utility	3,671,767	3,355,794
Less: Accumulated depreciation	1,089,872	1,018,173
	2,581,895	2,337,621
Construction work in progress	242,982	224,277
	2,824,877	2,561,898
Deferred Debits and Other Assets:
Regulatory assets	1,526,359	1,673,010
Prepaid pension	318,559	305,320
Derivative assets - long-term	167,122	99,761
Other	116,649	99,577
	2,128,689	2,177,668
Total Assets	$                  5,316,258	$                  5,206,894
The accompanying notes are an integral part of these consolidated financial statements.

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
At December 31,	2004	2003
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to banks	$                     15,000	$                              -
Notes payable to affiliated companies	90,025	91,125
Accounts payable	166,520	138,155
Accounts payable to affiliated companies	89,242	176,948
Accrued taxes	-	65,587
Accrued interest	14,203	10,361
Derivative liabilities - current	4,408	5,061
Other	65,951	60,691
	445,349	547,928
Rate Reduction Bonds	995,233	1,124,779
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	761,036	598,051
Accumulated deferred investment tax credits	88,540	90,885
Deferred contractual obligations	281,633	318,043
Regulatory liabilities	614,770	752,992
Derivative liabilities - long-term	42,809	49,505
Other	95,505	79,935
	1,884,293	1,889,411
Capitalization:
Long-Term Debt	1,052,891	830,149
Preferred Stock - Non-Redeemable	116,200	116,200
Common Stockholder's Equity:
Common stock, $10 par value - authorized
24,500,000 shares; 6,035,205 shares outstanding
in 2004 and 2003	60,352	60,352
Capital surplus, paid in	415,140	326,629
Retained earnings	347,176	311,793
Accumulated other comprehensive loss	(376)	(347)
Common Stockholder's Equity	822,292	698,427
Total Capitalization	1,991,383	1,644,776
Commitments and Contingencies (Note 6)
Total Liabilities and Capitalization	$               5,316,258	$                5,206,894
The accompanying notes are an integral part of these consolidated financial statements.

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2004	2003	2002
	(Thousands of Dollars)
Operating Revenues	$            2,832,924	$            2,704,524	$            2,507,036
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	1,698,335	1,602,240	1,477,347
Other	434,303	380,039	300,439
Maintenance	81,064	73,066	80,132
Depreciation	119,295	104,513	98,360
Amortization of regulatory assets, net	24,294	105,956	88,318
Amortization of rate reduction bonds	110,625	103,285	96,489
Taxes other than income taxes	142,919	142,339	137,299
Gain on sale of utility plant	-	-	(16,143)
Total operating expenses	2,610,835	2,511,438	2,262,241
Operating Income	222,089	193,086	244,795
Interest Expense:
Interest on long-term debt	43,308	39,815	41,332
Interest on rate reduction bonds	63,667	70,284	75,705
Other interest	3,072	508	3,925
Interest expense, net	110,047	110,607	120,962
Other Income, Net	21,513	4,564	22,112
Income Before Income Tax Expense	133,555	87,043	145,945
Income Tax Expense	45,539	18,135	60,333
Net Income	$                 88,016	$                 68,908	$                 85,612
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income	$                 88,016	$                 68,908	$                 85,612
Other comprehensive (loss)/income, net of tax:
Unrealized gains/(losses) on securities	37	152	(408)
Minimum supplemental executive retirement
pension liability adjustments	(66)	(136)	(22)
Other comprehensive (loss)/income, net of tax	(29)	16	(430)
Comprehensive Income	$                 87,987	$                 68,924	$                 85,182
The accompanying notes are an integral part of these consolidated financial statements.

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
	Common Stock
	Shares		Amount	Capital Surplus, Paid In	Retained Earnings	Accumulated Other Comprehensive Income/(Loss)	Total
		(Thousands of Dollars, except share information)
Balance at January 1, 2002	7,584,884		$        75,849	$         414,018	$       286,901	$                          67	$              776,835
Net income for 2002					85,612		85,612
Cash dividends on preferred stock					(5,559)		(5,559)
Cash dividends on common stock					(60,145)		(60,145)
Repurchase of common stock	(1,549,679)		(15,497)	(84,493)			(99,990)
Capital stock expenses, net				232			232
Allocation of benefits - ESOP				(2,458)	1,745		(713)
Other comprehensive loss						(430)	(430)
Balance at December 31, 2002	6,035,205		60,352	327,299	308,554	(363)	695,842
Net income for 2003					68,908		68,908
Cash dividends on preferred stock					(5,559)		(5,559)
Cash dividends on common stock					(60,110)		(60,110)
Capital stock expenses, net				186			186
Allocation of benefits - ESOP				(856)			(856)
Other comprehensive income						16	16
Balance at December 31, 2003	6,035,205		60,352	326,629	311,793	(347)	698,427
Net income for 2004					88,016		88,016
Cash dividends on preferred stock					(5,559)		(5,559)
Cash dividends on common stock					(47,074)		(47,074)
Capital contribution from NU parent				88,000			88,000
Tax deduction for stock options exercised and Employee        Stock Purchase
Plan disqualifying dispositions				823			823
Capital stock expenses, net				186			186
Allocation of benefits - ESOP				(498)			(498)
Other comprehensive loss						(29)	(29)
Balance at December 31, 2004	6,035,205		$        60,352	$         415,140	$       347,176	$                       (376)	$              822,292
The accompanying notes are an integral part of these consolidated financial statements.

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2004	2003	2002
	(Thousands of Dollars)
Operating Activities:
Net income	$                    88,016	$                 68,908	$                 85,612
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	1,440	5,164	398
Depreciation	119,295	104,513	98,360
Deferred income taxes and investment tax credits, net	102,394	(125,711)	(78,411)
Amortization of regulatory assets, net	24,294	105,956	88,318
Amortization of rate reduction bonds	110,625	103,285	96,489
(Deferral)/amortization of recoverable energy costs	(13,242)	19,191	30,787
Gain on sale of utility plant	-	-	(16,143)
Pension income	(6,763)	(14,047)	(29,781)
Regulatory (refunds)/overrecoveries	(137,537)	267,729	92,743
Other sources of cash	18,499	2,283	11,646
Other uses of cash	(73,745)	(110,171)	(33,984)
Changes in current assets and liabilities:
Restricted cash - LMP costs	93,630	(93,630)	-
Receivables and unbilled revenues, net	(4,201)	(2,008)	(37,833)
Materials and supplies	(1,630)	796	(1,017)
Investments in securitizable assets	27,074	12,443	27,459
Other current assets	(3,249)	6,886	(1,535)
Accounts payable	(59,341)	22,309	74,831
Accrued taxes	(65,587)	31,237	(643)
Other current liabilities	9,183	12,401	351
Net cash flows provided by operating activities	229,155	417,534	407,647
Investing Activities:
Investments in plant	(370,818)	(323,114)	(262,597)
Net proceeds from the sale of utility plant	-	-	35,887
Other investment activities	1,522	5,448	22,309
Net cash flows used in investing activities	(369,296)	(317,666)	(204,401)
Financing Activities:
Repurchase of common shares	-	-	(99,990)
Issuance of long-term debt	280,000	-	-
Retirement of rate reduction bonds	(129,546)	(120,949)	(112,924)
Capital contribution from Northeast Utilities	88,000	-	-
Increase in short-term debt	15,000	-	-
NU Money Pool (lending)/borrowing	(1,100)	93,025	75,300
Reacquisitions and retirements of long-term debt	(59,000)	-	-
Cash dividends on preferred stock	(5,559)	(5,559)	(5,559)
Cash dividends on common stock	(47,074)	(60,110)	(60,145)
Other financing activities	(786)	(620)	(542)
Net cash flows provided by/(used in) financing activities	139,935	(94,213)	(203,860)
Net (decrease)/increase in cash	(206)	5,655	(614)
Cash - beginning of period	5,814	159	773
Cash - end of period	$                      5,608	$                   5,814	$                      159
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized	$                  109,890	$               112,258	$               117,718
Income taxes	$                    24,915	$               105,167	$               141,724

The accompanying notes are an integral part of these consolidated financial statements.

Notes To Consolidated Financial Statements

1.   Summary of Significant Accounting Policies

A.

About The Connecticut Light and Power Company

The Connecticut Light and Power Company (CL&P or the company) is a wholly owned subsidiary of Northeast Utilities (NU).  CL&P is registered with the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934.  NU is registered with the SEC as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act), and NU, including CL&P, is subject to the provisions of the 1935 Act.  Arrangements among CL&P, other NU companies, outside agencies, and other utilities covering interconnections, interchange of electric power and sales of utility property, are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC.  CL&P is subject to further regulation for rates, accounting and other matters by the FERC and the Connecticut Department of Public Utility Control (DPUC).  CL&P, Public Service Company of New Hampshire (P SNH), and Western Massachusetts Electric Company (WMECO), furnish franchised retail electric service in Connecticut, New Hampshire and Massachusetts, respectively.  CL&P’s results include the operations of its distribution and transmission segments.   

Several wholly owned subsidiaries of NU provide support services for NU’s companies, including CL&P.  Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU’s companies.

Total CL&P purchases from Select Energy for CL&P's standard offer load and for other transactions with Select Energy represented approximately $611 million, approximately $688 million and approximately $631 million, for the years ended December 31, 2004, 2003 and 2002, respectively.

B.

Presentation

The consolidated financial statements of CL&P and of its subsidiaries, as applicable, include the accounts of all their respective subsidiaries.  Intercompany transactions have been eliminated in consolidation.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingencies at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Certain reclassifications of prior year's data have been made to conform with the current year’s presentation.  See Note 15, "Reclassification of Previously Issued Financial Statements," for the effects of the reclassifications.

C.

New Accounting Standards

Accounting for the Effect of Medicare Changes on Postretirement Benefits Other Than Pension (PBOP):On December 8, 2003, the President of the United States signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit and by adding a federal subsidy to qualifying plan sponsors of retiree health care benefit plans.  CL&P chose to reflect the impact on December 31, 2003 reported amounts with no impact on 2003 expenses, assets, or liabilities.  

On May 19, 2004, the Financial Accounting Standards Board (FASB) issued Staff Position (FSP) No. FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," to provide guidance on accounting for the effects of the aforementioned Medicare expansion.  This FSP concludes that the effects of the federal subsidy should be considered an actuarial gain and treated like similar gains and losses and requires certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits which are included in this annual report.  The accounting treatment under FSP No. FAS 106-2 is consistent with CL&P's accounting treatment at December 31, 2003 and reduced the projected benefit obligation by $3.6 million and $9.4 million in 2004 and 2003, respectively.  

Consolidation of Variable Interest Entities:  In December 2003, the FASB issued a revised version of FASB Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities," (FIN 46R).  FIN 46R resulted in fewer CL&P investments meeting the definition of a variable interest entity (VIE).  FIN 46R was effective for CL&P for the first quarter of 2004 and did not have an impact on CL&P's consolidated financial statements.

D.

Guarantees

At December 31, 2004, NU had outstanding guarantees on behalf of CL&P in the amount of $0.2 million.  A majority of these guarantees do not have established expiration dates, most are due to expire by December 31, 2005.

E.

Revenues

CL&P retail revenues are based on rates approved by the DPUC.  These regulated rates are applied to customers' use of energy to calculate a bill.  In general, rates can only be changed through formal proceedings with the DPUC.

CL&P utilizes regulatory commission-approved tracking mechanisms to track the recovery of certain incurred costs.  The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or underrecollections collected from customers in future periods.

Unbilled Revenues:  Unbilled revenues represent an estimate of electricity delivered to customers that has not been billed.  Unbilled revenues are assets on the balance sheet that become accounts receivable in the following month as customers are billed.  Such estimates are subject to adjustment when actual meter readings become available, when changes in estimating methodology occur and under other circumstances.

CL&P estimates unbilled revenues monthly using the requirements method.  The requirements method utilizes the total monthly volume of electricity or gas delivered to the system and applies a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers.  The total estimated monthly sales amount less the total monthly billed sales amount results in a monthly estimate of unbilled sales.  Unbilled revenues are estimated by first allocating sales to the respective rate classes, then applying an average rate to the estimate of unbilled sales.  The estimated DE factor can have a significant impact on estimated unbilled revenue amounts.

In accordance with management's policy of testing the estimate of unbilled revenues twice each year using the cycle method of estimating unbilled revenues, testing was performed in the second and fourth quarters of 2004 but did not have a material impact on earnings.  The cycle method uses the billed sales from each meter reading cycle and an estimate of unbilled days in each month based on the meter reading schedule.  The cycle method is more accurate than the requirements method when used in a mostly weather-neutral month.  

During 2003 the cycle method resulted in adjustments to the estimate of unbilled revenues that had a positive after-tax earnings impact of approximately $7.2 million.

Transmission Revenues:  Wholesale transmission revenues are based on rates and formulas that are approved by the FERC.  Most of CL&P’s wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and CL&P’s Local Network Service (LNS) tariff.  The RNS tariff, which is administered by the New England Independent System Operator, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be regional facilities.  This regional rate is reset on June 1st of each year.  The LNS tariff provides for the recovery of CL&P’s wholesale transmission revenue requirements, net of revenues received from other sources, including those revenues received under RNS rates.  CL&P’s LNS tariff is also reset on June 1st of each year to coincide with the change in RNS ra tes.  Additionally, CL&P’s LNS tariff provides for a true-up to actual costs which ensures that CL&P recovers its wholesale transmission revenue requirements, including an allowed ROE.  

A significant portion of CL&P's transmission business revenues is from charges to CL&P's distribution business.  The distribution business recovers these charges through rates charged to its retail customers.  The 2004 rates set in the CL&P distribution rate case contained a level of transmission revenue sufficient to recover CL&P's anticipated 2004 transmission costs.  CL&P does not have a transmission cost tracking mechanism.

F.

Derivative Accounting

Certain CL&P contracts are subject to unplanned netting and do not meet the definition of capacity contracts.  These non-trading derivative contracts are recorded at fair value, in accordance with Statement of Financial Accounting Standards (SFAS) No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," as derivative assets and liabilities with offsetting amounts recorded as regulatory liabilities and assets because the contracts are part of providing regulated electric service and because management believes that these amounts will be recovered or refunded in rates.

In accordance with Emerging Issues Task Force (EITF) in July 2003 on EITF Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-3," realized gains and losses on contracts that physically deliver and are not held for trading purposes should be reported on a net or gross basis depending on the relevant facts and circumstances.  CL&P has derivative sales contracts, and though these contracts may result in physical delivery, management has determined, based on the relevant facts and circumstances, that because these transactions are part of CL&P’s procurement activities, inclusion in operating expenses better depicts these sales activities.  At December 31, 2004, 2003 and 2002, the settlement of these derivative contracts that are not held for trading purpos es are reported on a net basis in expenses.

Accounting for Energy Contracts:  The accounting treatment for energy contracts entered into varies between contracts and depends on the intended use of the particular contract and on whether or not the contracts are derivatives.  

Non-derivative contracts that are entered into for the normal purchase or sale of energy to customers that will result in physical delivery are recorded at the point of delivery under accrual accounting.  

Derivative contracts that are entered into for the normal purchase and sale of energy and meet the normal purchase and sale exception to derivative accounting, as defined in SFAS No. 133 and amended by SFAS No. 149 (normal), are also recorded at the point of delivery under accrual accounting.

Both non-derivative contracts and derivative contracts that are normal are recorded in revenues when these contracts represent sales, and recorded in fuel, purchased and net interchange power when these contracts represent purchases,except for sales contracts that relate to procurement activities.  These contracts are recorded in fuel, purchased and net interchange power when settled.

Derivative contracts that are not held for trading purposes and that do not qualify as normal purchases and sales or hedges are non-trading derivative contracts.  These contracts are recorded on the consolidated balance sheets at fair value.

For further information regarding these contracts and their accounting, see Note 3, "Derivative Instruments," to the consolidated financial statements.

G.

Regulatory Accounting

The accounting policies of CL&P conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."

The transmission and distribution businesses of CL&P continue to be cost-of-service rate regulated.  Management believes the application of SFAS No. 71 to that portion of those businesses continues to be appropriate.  Management also believes it is probable that CL&P will recover its investments in long-lived assets, including regulatory assets.  In addition, all material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity.  

Regulatory Assets:  The components of CL&P's regulatory assets are as follows:

At December 31,
(Millions of Dollars)	2004	2003
Recoverable nuclear costs	$      -	$     16.4
Securitized assets	994.3	1,123.7
Income taxes, net	207.5	140.9
Unrecovered contractual obligations	213.4	221.8
Recoverable energy costs	43.4	30.1
Other	67.8	140.1
Totals	$1,526.4	$1,673.0

Additionally, CL&P had $11.4 million and $12.2 million of regulatory costs at December 31, 2004 and 2003, respectively, that are included in deferred debits and other assets - other on the accompanying consolidated balance sheets.  These amounts represent regulatory costs that have not yet been approved by the DPUC.  Management believes these assets are recoverable in future rates.

Recoverable Nuclear Costs:  In March 2001, CL&P sold its ownership interest in the Millstone nuclear units (Millstone).  The gain on the sale of approximately $521.6 million was used to offset recoverable nuclear costs.  These unamortized recoverable nuclear costs amounted to $16.4 million at December 31, 2003 and were fully recovered by December 31, 2004.

Securitized Assets:  In March 2001, CL&P issued $1.4 billion in rate reduction certificates.  CL&P used $1.1 billion of those proceeds to buyout or buydown certain contracts with independent power producers (IPP).  The unamortized CL&P securitized asset balance is $850 million and $960.5 million at December 31, 2004 and 2003, respectively.  CL&P used the remaining proceeds from the issuance of the rate reduction certificates to securitize a portion of its SFAS No. 109, "Accounting for Income Taxes," regulatory asset.  The securitized SFAS No. 109 regulatory asset had a balance remaining of $144.3 million and $163.2 million at December 31, 2004 and 2003, respectively.

Securitized assets are being recovered over the amortization period of their associated rate reduction certificates.  All outstanding rate reduction certificates of CL&P are scheduled to amortize by December 30, 2010.

Income Taxes, Net:  The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the DPUC and SFAS No. 109.  Differences in income taxes between SFAS No. 109 and the rate-making treatment of the DPUC are recorded as regulatory assets.  For further information regarding income taxes, see Note 1H, "Summary of Significant Accounting Policies - Income Taxes," and Note 13, "Income Tax Expense," to the consolidated financial statements.

Unrecovered Contractual Obligations:  CL&P, under the terms of contracts with Connecticut Yankee Atomic Power Company (CYAPC), Yankee Atomic Energy Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) (the Yankee Companies), is responsible for its proportionate share of the remaining costs of the units, including decommissioning.  These amounts are recorded as unrecovered contractual obligations.  A portion of these obligations was securitized in 2001 and is included in securitized regulatory assets.  For further information regarding unrecovered contractual obligations see Note 6E, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.

Recoverable Energy Costs:  Under the Energy Policy Act of 1992 (Energy Act), CL&P was assessed for its proportionate shares of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment).  The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost.  CL&P no longer owns nuclear generation but continues to recover these costs through rates.  At December 31, 2004 and 2003, CL&P’s total D&D Assessment deferrals were $10.9 million and $14.3 million, respectively, and have been recorded as recoverable energy costs. Also included in recoverable energy costs at December 31, 2004 is $32.5 million related to Federally Mandated Congestion Costs.  During 2003, CL&P paid for a temp orary generation resource in southwest Connecticut to help maintain reliability.  Costs for this resource of $15.8 million were recorded as recoverable energy costs at December 31, 2003.  

The majority of the recoverable energy costs are currently recovered in rates from CL&P's customers.

Regulatory Liabilities:  CL&P had $614.8 million and $753 million of regulatory liabilities at December 31, 2004 and 2003, respectively.  These amounts are comprised of the following:

At December 31,
(Millions of Dollars)	2004	2003
Cost of removal	$144.3	$150.0
CTA, GSC, and SBC overcollections	200.0	333.7
Regulatory liabilities offsetting   derivative assets	191.4	115.4
Other regulatory liabilities	79.1	153.9
Totals	$614.8	$753.0

Under SFAS No. 71, CL&P currently recovers amounts in rates for future costs of removal of plant assets.  Historically, these amounts were included as a component of accumulated depreciation until spent.  These amounts are classified as regulatory liabilities on the accompanying consolidated balance sheets in accordance with SFAS No. 143 "Accounting for Asset Retirement Obligations."  

The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs while the Generation Service Charge (GSC) allows CL&P to recover the costs of the procurement of energy for standard offer service.  The System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced workers protection costs.  

The regulatory liabilities offsetting derivative assets relate to the fair value of CL&P IPP contracts that will benefit ratepayers in the future.  

H.

Income Taxes

The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the DPUC and SFAS No. 109.

The tax effects of temporary differences that give rise to the current and long-term net accumulated deferred tax obligations are as follows:

	At December 31,
(Millions of Dollars)	2004	2003
Deferred tax liabilities – current:
Property tax accruals	$  20.0	$  17.8
Total deferred tax liabilities – current	20.0	17.8
Deferred tax assets – current:
Allowance for uncollectible accounts	3.7	6.9
Total deferred tax assets – current	3.7	6.9
Net deferred tax liabilities – current	16.3	10.9
Deferred tax liabilities – long-term:
Accelerated depreciation and other     plant related differences	621.4	533.8
Securitized costs	51.8	58.8
Income tax gross-up	166.2	136.5
Employee benefits	126.2	121.1
Other	17.3	20.5
Total deferred tax liabilities -  long-term	982.9	870.7
Deferred tax assets – long-term:
Regulatory deferrals	174.3	199.3
Employee benefits	10.8	7.0
Income tax gross-up	25.9	20.9
Other	10.9	45.4
Total deferred tax assets – long-term	221.9	272.6
Net deferred tax liabilities – long-term	761.0	598.1
Net deferred tax liabilities	$777.3	$609.0

NU and its subsidiaries, including CL&P, file a consolidated federal income tax return.  NU and its subsidiaries, including CL&P, are parties to a tax allocation agreement under which taxable subsidiaries pay no more taxes than they would have otherwise paid had they filed a stand-alone tax return.  Subsidiaries generating tax losses are similarly paid for their losses when utilized.

At December 31, 2004, CL&P had state tax credit carry forwards of $6.8 million that expire on December 31, 2009.

In 2000, NU requested from the Internal Revenue Service (IRS) a Private Letter Ruling (PLR) regarding the treatment of unamortized investment tax credits (ITC) and excess deferred income taxes (EDIT) related to generation assets that have been sold.  EDIT are temporary differences between book and taxable income that were recorded when the federal statutory tax rate was higher than it is now or when those differences were expected to be resolved.  The PLR addresses whether or not EDIT and ITC can be returned to customers, which without a PLR management believes would represent a violation of current tax law.  The IRS declared a moratorium on issuing PLRs until final regulations on the return of EDIT and ITC to

regulated customers are issued by the Treasury Department.  Proposed regulations were issued in March 2003, and a hearing took place in June 2003.  The proposed new regulations would allow the return of EDIT and ITC to regulated customers without violating the tax law.  Also, under the proposed regulations, a company could elect to apply the regulation retroactively.  The Treasury Department is currently deliberating the comments received at the hearing.  The ultimate results of this contingency could have a positive impact on CL&P's earnings.

I.

Depreciation

The provision for depreciation on utility assets is calculated using the straight-line method based on the estimated remaining useful lives of depreciable plant-in-service, which range primarily from 3 years to 50 years, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable.  Depreciation rates are applied to plant-in-service from the time it is placed in service.  When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation.  Cost of removal is classified as a regulatory liability.  The depreciation rates for the several classes of electric utility plant-in-service are equivalent to a composite rate of 3.4 percent in 2004, 3.3 percent in 2003 and 3.2 percent in 2002.

J.

Jointly Owned Electric Utility Plant

At December 31, 2004, CL&P owns common stock in the Yankee Companies.  CL&P’s ownership interest in the Yankee Companies at December 31, 2004, which are accounted for on the equity method are 34.5 percent of CYAPC, 24.5 percent of YAEC and 12 percent of MYAPC.  In 2003, CL&P sold its 10.1 percent ownership interest in Vermont Yankee Nuclear Power Corporation (VYNPC).CL&P’s total equity investment in the Yankee Companies at December 31, 2004 and 2003, was $19.4 million and $21.8 million, respectively.  Earnings related to these equity investments are included in other income/(loss) on the accompanying consolidated statements of income.  For further information, see Note 1Q, "Other Income/(Loss)," to the consolidated financial statements.  Each of the remaining Yankee Companies owns a single nuclear generating plant which is being decommissioned.

CL&P owns 34.5 percent of the common stock of CYAPC with a carrying value of $15 million at December 31, 2004.  CYAPC is involved in litigation over the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel).  Management believes that this litigation has not impaired the value of its investment in CYAPC at December 31, 2004 but will continue to evaluate the impact of the litigation on CL&P's investment.  For further information regarding the Bechtel litigation, see Note 6E, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.

K.

Allowance for Funds Used During Construction

The allowance for funds used during construction (AFUDC) is a non-cash item that is included in the cost of utility plant and represents the cost of borrowed and equity funds used to finance construction.  The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense and the cost of equity funds is recorded as other income on the consolidated statements of income as follows:  

For the Years Ended December 31,
(Millions of Dollars, except percentages)	2004	2003	2002
Borrowed funds	$3.1	$3.0	$2.7
Equity funds	3.4	5.8	5.1
Totals	$6.5	$8.8	$7.8
Average AFUDC rates	4.1%	7.9%	8.2%

The average AFUDC rate is based on a FERC-prescribed formula that develops an average rate using the cost of the company's short-term financings as well as the company's capitalization (preferred stock, long-term debt and common equity).  The average rate is applied to eligible construction work in progress amounts to calculate AFUDC.

L. Sale of Customer Receivables

At December 31, 2004 and 2003, CL&P had sold an undivided interest in its accounts receivable of $90 million and $80 million, respectively, to a financial institution with limited recourse through CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. CRC can sell up to $100 million of an undivided interest in its accounts receivable and unbilled revenues.  At December 31, 2004 and 2003, the reserve requirements calculated in accordance with the Receivables Purchase and Sale Agreement were $18.8 million and $29.3 million, respectively.  These reserve amounts are deducted from the amount of receivables eligible for sale at the time.  Concentrations of credit risk to the purchaser under this agreement with respect to the receivables are limited due to CL&P's diverse customer base within its service territory.

At December 31, 2004 and 2003, amounts sold to CRC by CL&P but not sold to the financial institution totaling $139.4 million and $166.5 million, respectively, are included in investments in securitizable assets on the accompanying consolidated balance sheets.  These amounts would be excluded from CL&P’s assets in the event of CL&P’s bankruptcy.  On July 7, 2004, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 6, 2005, and the termination date of the facility was extended to July 3, 2007.  CL&P’s continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables.

The transfer of receivables to the financial institution under this arrangement qualifies for sale treatment under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement of SFAS No. 125."

M.

Asset Retirement Obligations

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations."  This statement requires that legal obligations associated with the retirement of property, plant and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made.  SFAS No. 143 was effective on January 1, 2003, for CL&P.  Management has completed its

review process for potential asset retirement obligations (ARO) and has not identified any material AROs that have been incurred.  However, management has identified certain removal obligations that arise in the ordinary course of business or have a low probability of occurring.  These types of obligations primarily relate to transmission and distribution lines and poles, telecommunication towers, transmission cables and certain FERC or state regulatory agency re-licensing issues.  These obligations are AROs that have not been incurred or are not material in nature.

On June 17, 2004, the FASB issued the proposed interpretation, "Accounting for Conditional Asset Retirement Obligations."  The proposed interpretation requires an entity to recognize a liability for the fair value of an ARO that is conditional on a future event if the liability’s fair value can be reasonably estimated and clarifies that there are no circumstances in which a law or regulation obligates an entity to perform retirement activities but then allows the entity to permanently avoid settling the obligation.

If adopted in its current form, there may be an impact to CL&P for AROs that CL&P currently concludes have not been incurred (conditional obligations).  These conditional obligations may include utility poles and asbestos that, if removed or disturbed by construction or demolition, creates a disposal obligation.  Management is in the process of evaluating the impact of the interpretation on CL&P.  The interpretation is scheduled to be issued in the first quarter of 2005 and would be effective for CL&P no later than December 31, 2005.

A portion of CL&P's rates is intended to recover the cost of removal of certain utility assets.  The amounts recovered do not represent AROs and are recorded as regulatory liabilities.  At December 31, 2004 and 2003, cost of removal was $144.3 million and $150 million, respectively.

N.

Materials and Supplies

Materials and supplies include materials purchased primarily for construction, operation and maintenance (O&M) purposes.  Materials and supplies are valued at the lower of average cost or market.

O. Restricted Cash – LMP Costs

Restricted cash - LMP costs represents incremental locational marginal pricing (LMP) cost amounts that were collected by CL&P and deposited into an escrow account.  

At December 31, 2003, restricted cash - LMP costs totaled $93.6 million, and an additional $30 million was deposited in 2004. During the third quarter of 2004, $83 million of the amount was paid to CL&P’s standard offer suppliers in accordance with the FERC approved standard market design (SMD) settlement.  The remaining $41 million was released from the escrow account in the third quarter of 2004 and was refunded to CL&P's customers as a credit on bills from September to December of 2004.

P.

Excise Taxes

Certain excise taxes levied by state or local governments are collected by CL&P from its customers.  These excise taxes are accounted for on a gross basis with collections in revenues and payments in expenses.  For the years ended December 31, 2004, 2003 and 2002, gross receipts taxes, franchise taxes and other excise taxes of $75.8 million, $76.3 million, and $74.4 million, respectively, are included in operating revenues and taxes other than income taxes on the accompanying consolidatedstatements of income.  

Q.

Other Income/(Loss)

The pre-tax components of CL&P's other income/(loss) items are as follows:

For the Years Ended December 31,
(Millions of Dollars)	2004	2003	2002
Other Income:
Investment income	$   7.4	$   4.7	$11.2
CL&P procurement fee	11.7	-	-
AFUDC - equity funds	3.4	5.8	5.1
Conservation load      management incentive	4.0	1.4	3.5
Return on regulatory     deferrals	3.4	-	-
Other	2.3	7.7	11.5
Total Other Income	32.2	19.6	31.3
Other Loss:
Charitable donations	(2.8)	(4.6)	(2.8)
Costs not recoverable from     regulated customers	(3.2)	(4.3)	(0.9)
Other	(4.7)	(6.1)	(5.5)
Total Other Loss	(10.7)	(15.0)	(9.2)
Totals	$  21.5	$   4.6	$22.1

Investment income includes equity in earnings of regional nuclear generating companies of $0.6 million in 2004, $1.8 million in 2003 and $6 million in 2002.  Equity in earnings relates to CL&P's investment in the Yankee Companies.  

None of the amounts in either other income - other or other loss - other are individually significant.  

R.

Provision for Uncollectible Accounts

CL&P maintains a provision for uncollectible accounts to record its receivables at an estimated net realizable value.  This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivables aging category, historical collection and write-off experience and management's assessment of individual customer collectibility.  Management reviews at least quarterly the collectibility of the receivables, and if circumstances change, collectibility estimates are adjusted accordingly.  Receivable balances are written-off against theprovision for uncollectibleaccounts when these balances are deemed to be uncollectible.  

2.   Short-Term Debt    

Limits:  The amount of short-term borrowings that may be incurred by CL&P is subject to periodic approval by either the SEC under the 1935 Act or by the DPUC.  On June 30, 2004, the SEC granted authorization allowing CL&P to incur total short-term borrowings up to a maximum $450 million through June 30, 2007.  The SEC also granted authorization for borrowing through the NU Money Pool (Pool).  

The charter of CL&P contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur.  At meetings in November 2003, CL&P obtained authorization from its stockholders to issue unsecured indebtedness with a maturity of less than 10 years in excess of the 10 percent of total capitalization limitation in CL&P's charter, provided that all unsecured indebtedness would not exceed 20 percent of total capitalization for a ten-year period expiring March 2014.  On March 18, 2004, the SEC approved this change in CL&P's charter.  As of December 31, 2004, CL&P is permitted to incur $394.8 million of additional unsecured debt.

Credit Agreement: On November 8, 2004, CL&P entered into a 5-year unsecured revolving credit facility under which CL&P can borrow up to $200 million.  This facility replaces a $300 million credit facility that expired on November 8, 2004.  Unless extended, the credit facility will expire on November 6, 2009.  At December 31, 2004, CL&P had $15 million borrowings under this credit facility.  CL&P had no borrowings outstanding under this facility at December 31, 2003.

Under the aforementioned credit agreement, CL&P may borrow at fixed or variable rates plus an applicable margin based upon certain debt ratings, as rated by the lower of Standard and Poor’s or Moody’s Investors Service.  The weighted-average interest rate on CL&P’s notes payable to banks outstanding on December 31, 2004 was 5.25 percent.

Under the credit agreement, CL&P must comply with certain financial and non-financial covenants as are customarily included in such agreements, including but not limited to, consolidated debt ratios andinterest coverage ratios.  The most restrictive financial covenant is the interest coverage ratio.  CL&P currently is and expects to remain in compliance with these covenants.  Amounts outstanding under these credit facilities are classified as current liabilities as notes payable to banks on the accompanying consolidated balance sheets as management anticipates that all borrowings under these credit facilities will be outstanding for no more than 364 days at any one time.

Pool:  CL&P is a member of the Pool.  The Pool provides a more efficient use of the cash resources of NU and reduces outside short-term borrowings.  NUSCO administers the Pool as agent for the member companies.  Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent.  NU parent may lend to the Pool but may not borrow.  Funds may be withdrawn from or repaid to the Pool at any time without prior notice.  Investing and borrowing subsidiaries receive or pay interest based on the average daily federal funds rate.  Borrowings based on loans from NU parent, however, bear interest at NU parent’s cost and must be repaid based upon the terms of NU parent’s original borrowing.  At December 31, 2004 and 2003, CL&P had borrowings of $90 million and $91.1 million from the Pool, respectively. &n bsp;The interest rate on borrowings from the Pool at December 31, 2004 and 2003 was 2.24 percent and 1 percent, respectively.

3.   Derivative Instruments

Contracts that are derivatives but do not meet the definition of a cash flow hedge and cannot be designated as being used for normal purchases or normal sales are also recorded at fair value with changes in fair value included in earnings. For those contracts that meet the definition of a derivative and meet the cash flow hedge requirements, the changes in the fair value of the effective portion of those contracts are generally recognized in accumulated other comprehensive income until the underlying transactions occur.  For contracts that meet the definition of a derivative but do not meet the hedging requirements, and for the ineffective portion of contracts that meet the cash flow hedge requirements, the changes in fair value of those contracts are recognized currently in earnings.  Derivative contracts designated as fair value hedges and the item they are hedging are both recorded at fair value on the consolidat ed balance sheets.  Derivative contracts that are entered into as a normal purchase or sale and will result in physical delivery, and are documented as such, are recognized in revenue and expense when such deliveries occur.

CL&P has two IPP contracts to purchase power that contain pricing provisions that are not clearly and closely related to the price of power and therefore do not qualify for the normal purchases and sales exception.  The fair values of these IPP non-trading derivatives at December 31, 2004 include a derivative asset with a fair value of $191.3 million and a derivative liability with a fair value of $47.2 million.  The fair values of these IPP non-trading derivatives at December 31, 2003 include a derivative asset with a fair value of $115.4 million and a derivative liability with a fair value of $54.6 million.  An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of the stranded costs, and management believes that these costs will continue to be recovered or refunded in rates.  

4.   Pension Benefits and Postretirement Benefits Other Than Pensions   

Pension Benefits:  CL&P participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees.  Benefits are based on years of service and the employees’ highest eligible compensation during 60 consecutive months of employment.  Pre-tax pension income was $14.3 million in 2004, $29.1 million in 2003, and $50.6 million in 2002.  These amounts exclude pension settlements, curtailments and net special termination expenses of $1.1 million in 2004.  CL&P uses a December 31 measurement date for the Pension Plan.  Pension income attributable to earnings is as follows:

	For the Years Ended December 31 ,
(Millions of Dollars)	2004	2003	2002
Pension income before  settlements, curtailments   and special termination benefits	$(14.3)	$(29.1)	$(50.6)
Net pension income   capitalized as utility plant	6.5	15.1	20.8
Net pension income before   settlements, curtailments   and special termination  benefits	(7.8)	(14.0)	(29.8)
Settlements, curtailments and   special termination benefits   reflected in earnings	1.1	-	-
Total pension income   included in earnings	$ (6.7)	$(14.0)	$(29.8)

Pension Settlements, Curtailments and Special Termination Benefits:  As a result of litigation with nineteen former employees, in April 2004, NU was ordered by the court to modify its retirement plan to include special retirement benefits for fifteen of these former employees retroactive to the dates of their retirement and increased future monthly benefit payments.  In the third quarter of 2004, NU withdrew its appeal of the court’s ruling.  As a result, CL&P recorded $1.1 million in special termination benefits related to this litigation in 2004.

There were no settlements, curtailments or special termination benefits in 2003 and none in 2002 that impacted earnings.

Effective February 1, 2002, certain CL&P employees who were displaced were eligible for a Voluntary Retirement Program (VRP).  The VRP supplements the Pension Plan and provides special provisions.  Eligible employees include non-bargaining unit employees or employees belonging to a collective bargaining unit that has agreed to accept the VRP who are active participants in the Pension Plan at January 1, 2002, and that have been displaced as part of the reorganization between January 22, 2002 and March 2003.  Eligible employees received a special retirement benefit under the VRP whose value was roughly equivalent to a multiple of base paybased on years of credited service.  During 2002, CL&P recorded an expense of $8.1 million associated with special pension termination benefits related to the VRP.  CL&P believes that the cost of the VRP is probable of recovery th rough regulated utility rates, and accordingly, the $8.1 million was recorded as a regulatory asset with no impact on 2002 earnings.

Market-Related Value of Pension Plan Assets:  CL&P bases the actuarial determination of pension plan income or expense on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets.  Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.

Postretirement Benefits Other Than Pensions:  CL&P also provides certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (PBOP Plan).  These benefits are available for employees retiring from CL&P who have met specified service requirements.  For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost.  These costs are charged to expense over the estimated work life of the employee.  CL&P uses a December 31 measurement date for the PBOP Plan.  

CL&P annually funds postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible.  Currently, there are no pending regulatory actions regarding postretirement benefit costs and there are no postretirement benefit costs that are deferred as regulatory assets.

Impact of New Medicare Changes on PBOP:  On December 8, 2003, the President signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit starting in 2006 for Medicare-eligible retirees as well as a federal subsidy to plan sponsors of retiree health care benefit plans who provide a prescription drug benefit at least actuarially equivalent to the new Medicare benefit.

Based on the current PBOP Plan provisions, CL&P’s actuaries believe that CL&P will qualify for this federal subsidy because the actuarial value of CL&P’s PBOP Plan is estimated to be 60 percent greater than that of the standard Medicare benefit.  CL&P will directly benefit from the federal subsidy for retirees who retired before 1991.  For other retirees, management does not believe that CL&P will benefit from the subsidy because CL&P’s cost support for these retirees is capped at a fixed dollar commitment.

Based on the most recent actuarial valuation as of January 1, 2004, the impact of the Medicare program has been revised from a $9.4 million decrease in the PBOP benefit obligation at December 31, 2003 to $13 million at January 1, 2004.  The total $13 million decrease consists of $10 million as a direct result of the subsidy for certain non-capped retirees and $3 million related to changes in participation assumptions for capped

retirees and future retirees as a result of the subsidy.  The total $13 million decrease is currently being amortized as a reduction to PBOP expense over approximately 13 years.  For the year ended December 31, 2004, this reduction in PBOP expense totaled approximately $1.7 million, including amortization of the actuarial gain of $0.9 million and a reduction in interest cost and service cost based on a lower PBOP benefit obligation of $0.8 million.  

PBOP Settlements, Curtailments and Special Termination Benefits:   There were no settlements, curtailments or special termination benefits in 2004, 2003 and 2002.  

The following table represents information on the plans’ benefit obligation, fair value of plan assets, and the respective plans’ funded status:

	At December 31,
	Pension Benefits		Postretirement Benefits
(Millions of Dollars)	2004	2003	2004	2003
Change in benefit obligation
Benefit obligation at beginning of year	$(731.3)	$(680.3)	$(169.3)	$(167.0)
Service cost	(14.7)	(12.8)	(2.1)	(2.0)
Interest cost	(44.8)	(44.4)	(10.5)	(11.3)
Medicare prescription drug benefit impact	N/A	N/A	-	9.4
Transfers	(2.0)	1.4	(0.8)	-
Actuarial loss	(52.0)	(39.1)	(24.8)	(14.2)
Benefits paid - excluding lump sum payments	45.1	41.7	15.1	15.8
Benefits paid - lump sum payments	0.8	2.2	-	-
Special termination benefits	(1.1)	-	-	-
Benefit obligation at end of year	$(800.0)	$(731.3)	$  (192.4)	$(169.3)
Change in plan assets
Fair value of plan assets at beginning of year	$  899.3	$  752.7	$      64.3	$     50.3
Actual return on plan assets	110.0	191.9	6.3	13.2
Employer contribution	-	-	18.6	16.6
Transfers	2.0	(1.4)	0.8	-
Benefits paid - excluding lump sum payments	(45.1)	(41.7)	(15.1)	(15.8)
Benefits paid - lump sum payments	(0.8)	(2.2)	-	-
Fair value of plan assets at end of year	$  965.4	$  899.3	$     74.9	$     64.3
Funded status at December 31	$  165.4	$  168.0	$(117.5)	$ (105.0)
Unrecognized transition obligation/(asset)	-	(0.9)	50.3	56.5
Unrecognized prior service cost	23.2	26.1	-	-
Unrecognized net loss	130.0	112.1	66.5	48.5
Prepaid/(accrued) benefit cost	$  318.6	$  305.3	$    (0.7)	$          -

The accumulated benefit obligation for the Plan was $696.8 million and $645.9 million at December 31, 2004 and 2003, respectively.

The following actuarial assumptions were used in calculating the plans’ year end funded status:

	At December 31,
Balance Sheets	Pension Benefits		Postretirement Benefits
	2004	2003	2004	2003
Discount rate	6.00%	6.25%	5.50%	6.25%
Compensation/progression rate	4.00%	3.75%	N/A	N/A
Health care cost trend rate	N/A	N/A	8.00%	9.00%

The components of net periodic (income)/expense are as follows:

	For the Years Ended December 31,
	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2004	2003	2002	2004		2003	2002
Service cost	$ 14.7	$ 12.8	$ 11.7	$  2.1		$  2.0	$  2.0
Interest cost	44.8	44.4	44.8	10.5		11.3	12.0
Expected return on plan assets	(81.3)	(84.1)	(94.2)	(4.6)		(5.1)	(5.4)
Amortization of unrecognized net   transition (asset)/obligation	(0.9)	(0.9)	(0.9)	6.3		6.3	6.9
Amortization of prior service cost	3.0	3.0	3.0	-		-	-
Amortization of actuarial loss/(gain)	5.4	(4.3)	(15.0)	-		-	-
Other amortization, net	-	-	-	4.3		2.1	1.9
Net periodic (income)/expense - before   special termination benefits	(14.3)	(29.1)	(50.6)	18.6		16.6	17.4
Special termination benefits expense	1.1	-	8.1	-		-	-
Total - special termination   Benefits	1.1	-	8.1	-		-	-
Total - net periodic (income)/expense	$(13.2)	$(29.1)	$(42.5)	$18.6		$16.6	$17.4

For calculating pension and postretirement benefit income and expense amounts, the following assumptions were used:

	For the Years Ended December 31,
Statements of Income	Pension Benefits				Postretirement Benefits
	2004	2003	2002	2004		2003	2002
Discount rate	6.25%	6.75%	7.25%	6.25%		6.75%	7.25%
Expected long-term rate of return	8.75%	8.75%	9.25%	N/A		N/A	N/A
Compensation/progression rate	3.75%	4.00%	4.25%	N/A		N/A	N/A
Expected long-term rate of return -
Health assets, net of tax	N/A	N/A	N/A	6.85%		6.85%	7.25%
Life assets and non-taxable     health assets	N/A	N/A	N/A	8.75%		8.75%	9.25%

The following table represents the PBOP assumed health care cost trend rate for the next year and the assumed ultimate trend rate:

	Year Following December 31,
	2004	2003
Health care cost trend rate   assumed for next year	7.00%	8.00%
Rate to which health care   cost trend rate is assumed to   decline (the ultimate trend   rate)	5.00%	5.00%
Year that the rate reaches the   ultimate trend rate	2007	2007

The annual per capita cost of covered health care benefits was assumed to decrease by one percentage point each year through 2007.  

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans.  The effect of changing the assumed health care cost trend rate by one percentage point in each year would have the following effects:

(Millions of Dollars)	One Percentage Point Increase	One Percentage Point Decrease
Effect on total service and   interest cost components	$0.4	$(0.3)
Effect on postretirement   benefit obligation	$6.2	$(5.5)

CL&P's investment strategy for its Pension Plan and PBOP Plan is to maximize the long-term rate of return on those plans' assets within an acceptable level of risk.  The investment strategy establishes target allocations, which are regularly reviewed and periodically rebalanced.  CL&P's expected long-term rates of return on Pension Plan assets and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return.  In developing its expected long-term rate of return assumptions for the Pension Plan and the PBOP Plan, CL&P also evaluated input from actuaries and consultants as well as long-term inflation assumptions and CL&P's historical 20-year compounded return of approximately 11 percent.  The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long-term rate of return assumptions by asset category are as foll ows:

At December 31,

	Pension Benefits		Postretirement Benefits
	2004 and 2003		2004 and 2003
	Target Asset	Assumed Rate of	Target Asset	Assumed Rate of
Asset Category	Allocation	Return	Allocation	Return
Equity securities:
United States	45%	9.25%	55%	9.25%
Non-United States	14%	9.25%	11%	9.25%
Emerging markets	3%	10.25%	2%	10.25%
Private	8%	14.25%	-	-
Debt Securities:   Fixed income	20%	5.50%	27%	5.50%
High yield fixed income	5%	7.50%	5%	7.50%
Real estate	5%	7.50%	-	-

The actual asset allocations at December 31, 2004 and 2003, approximated these target asset allocations.  The plans’ actual weighted-average asset allocations by asset category are as follows:  

	At December 31,
	Pension Benefits		Postretirement                   Benefits
Asset Category	2004	2003	2004	2003
Equity securities:
United States	47%	47%	55%	59%
Non-United States	17%	18%	14%	12%
Emerging markets	3%	3%	1%	1%
Private	4%	3%	-	-
Debt Securities:   Fixed income	19%	19%	28%	25%
High yield fixed income	5%	5%	2%	3%
Real estate	5%	5%	-	-
Total	100%	100%	100%	100%

Estimated Future Benefit Payments:  The following benefit payments, which reflect expected future service, are expected to be paid for the Pension and PBOP Plans:

(Millions of Dollars)
Year	Pension Benefits	Postretirement Benefits	Government Subsidy
2005	$ 45.1	$16.9	$   -
2006	46.2	17.2	1.1
2007	47.6	17.3	1.1
2008	48.8	17.1	1.1
2009	50.1	16.8	1.1
2010-2014	275.1	78.5	5.0

Government subsidy represents amounts expected to be received from the federal government for the new Medicare prescription drug benefit under the PBOP Plan.

Contributions:  CL&P does not expect to make any contributions to the Pension Plan in 2005 and expects to make $22.1 million in contributions to the PBOP Plan in 2005.  

Currently, CL&P’s policy is to annually fund an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and Internal Revenue Code.

Postretirement health plan assets for non-union employees are subject to federal income taxes.

5.   Nuclear Generation Asset Divestitures

Seabrook:  On November 1, 2002, CL&P consummated the sale of its 4.06 percent ownership interest in Seabrook to a subsidiary of FPL Group, Inc. (FPL).  CL&P, North Atlantic Energy Corporation and certain other of the joint owners collectively sold 88.2 percent of Seabrook to FPL.  CL&P received approximately $36 million of total cash proceeds from the sale of Seabrook.  CL&P recorded a gain on the sale in the amount of approximately $16 million, which was primarily used to offset stranded costs.

In the third quarter of 2002, CL&P received regulatory approvals for the sale of Seabrook from the DPUC.  As a result of this approval, CL&P eliminated $0.6 million, on an after-tax basis, of reserves related to its ownership share of certain Seabrook assets.

VYNPC:  On July 31, 2002, VYNPC consummated the sale of its nuclear generating plant to a subsidiary of Entergy Corporation (Entergy) for approximately $180 million.  As part of the sale, Entergy assumed responsibility for decommissioning VYNPC's nuclear generating unit.  In 2003, CL&P sold its 10.1 percent ownership interest in VYNPC.  CL&P will continue to buy approximately 9.5 percent of the plant's output through March 2012 at a range of fixed prices.  

6.   Commitments and Contingencies   

A.

Regulatory Developments and Rate Matters

CTA and SBC Reconciliation:  The CTA allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs, while the SBC allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced worker protection costs.  

On April 1, 2004, CL&P filed its 2003 CTA and SBC reconciliation with the DPUC, which compares CTA and SBC revenues to revenue requirements.  A final decision in the 2003 CTA and SBC docket was issued on August 4, 2004 and ordered a refund to customers of $88.5 million over a seven-month period beginning with October 2004 consumption.  

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.

B.

Environmental Matters

General:  CL&P is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment.  These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites.  As such, CL&P has an active environmental auditing and training program and believes that it is substantially in compliance with all enacted laws and regulations.

Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated.  The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, including, no action is required or several different remedies ranging from establishing institutional controls to full site remediation and monitoring.  

These estimates are subjective in nature as they take into consideration several different remediation options at each specific site.  The reliability and precision of these estimates can be affected by several factors including new information concerning either the level of contamination at the site, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.  

The amounts recorded as environmental liabilities on the consolidated balance sheets represent management’s best estimate of the liability for environmental costs and takes into consideration site assessment and remediation costs.  Based on currently available information for estimated site assessment and remediation costs at December 31, 2004 and 2003, CL&P had $7.8 million and $7.9 million, respectively, recorded as environmental reserves.  A reconciliation of the total amount reserved at December 31, 2004 and 2003 is as follows:

(Millions of Dollars)	For the Years Ended December 31,
	2004	2003
Balance at beginning of year	$7.9	$ 7.3
Additions and adjustments	0.2	0.7
Payments	(0.3)	(0.1)
Balance at end of year	$7.8	$7.9

CL&P currently has 12 sites included in the environmental reserve.  Of those 12 sites, three sites are in the remediation or long-term monitoring phase, four sites have had site assessments completed and the remaining five sites are in the preliminary stages of site assessment.

For three sites that are included in the company's liability for environmental costs, the information known and nature of the remediation options at those sites allow an estimate of the range of losses to be made.  These sites primarily relate to manufactured gas plant (MGP) sites.  At December 31, 2004, $1.7 million has been accrued as a liability for these sites, which represents management's best estimate of the liability for environmental costs.  This amount differs from an estimated range of loss from $1.6 million to $6 million as management utilizes the probabilistic model approach to make its estimate of the liability for environmental costs.  For the nine remaining sites for which an estimate is based on the probabilistic model approach, determining a range of estimated losses is not possible.

These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties.  The environmental reserve includes sites at different stages of discovery and remediation and does not include any unasserted claims.  

At December 31, 2004, there are five sites for which there are unasserted claims, however, any related remediation costs are not probable or estimable at this time.  CL&P's environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non-recurring clean up costs.

MGP Sites:  MGP sites comprise the largest portion of CL&P's environmental liability.  MGPs are sites that manufactured gas from coal produced certain byproducts that may pose risk to human health and the environment.  At December 31, 2004 and 2003, $6.5 million represented amounts for the site assessment and remediation of MGPs.  

At December 31, 2004, CL&P has one site that is held for sale.  The site, a former MGP site, is currently held for sale under a pending purchase and sale agreement.  NU is currently remediating the property and has been deferring the costs associated with those remediation efforts as allowed by a regulatory order.  At December 31, 2004, CL&P had $7.9 million related to remediation efforts at the property and other sale costs recorded in other deferred debits on the accompanying consolidated balance sheets.

A final decision was reached by the DPUC, on January 19, 2005, which approved the sale proceedings of the former MGP site.  The final decision approved the price of $24 million for the sale of the land and also approved the deferral of the gain in the amount of $13.8 million ($8.3 million after-tax).  The purchase and sale agreement releases CL&P from all environmental claims arising out of or in connection with the property.

CERCLA Matters:  The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its’ amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages.  Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred.  CL&P has two superfund sites under CERCLA for which it has been notified that it is a potentially responsible party (PRP).  For sites where there are other PRPs and CL&P is not managing the site assessment and remediation, the liability accrued represents CL&P's estimate of what it will need to pay to settle its obligations with respect to the site.

It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters.  As this information becomes available management will continue to assess the potential exposure and adjust the reserves accordingly, as necessary.  

Rate Recovery:  CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism.  Accordingly, changes in CL&P's environmental reserves impact CL&P's earnings.  

C.

Spent Nuclear Fuel Disposal Costs

Under the Nuclear Waste Policy Act of 1982, CL&P must pay the DOE for the disposal of spent nuclear fuel and high-level radioactive waste.  The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste.  For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Fuel), an accrual has been recorded for the full liability, and payment must be made prior to the first delivery of spent fuel to the DOE.  Until such payment is made, the outstanding balance will continue to accrue interest at the 3-month treasury bill yield rate.  At December 31, 2004 and 2003, fees due to the DOE for the disposal of Prior Period Fuel were $210.4 million and $207.7 million, respectively, including interest costs of $143.9 million and $141.2 million, respectively.

D.

Long-Term Contractual Arrangements

VYNPC: Previously under the terms of its agreement, CL&P paid its ownership (or entitlement) share of costs, which included depreciation, O&M expenses, taxes, the estimated cost of decommissioning, and a return on invested capital to VYNPC and recorded these costs as purchased-power expenses.  On July 31, 2002, VYNPC consummated the sale of its nuclear generating unit to a subsidiary of Entergy for approximately $180 million.  Under the terms of the sale, CL&P will continue to buy approximately 9.5 percent of the plant's output through March 2012 at a range of fixed prices.  The total cost of purchases under contracts with VYNPC amounted to $15.9 million in 2004, $17.8 million in 2003 and $16.4 million in 2002.

Electricity Procurement Contracts:  CL&P has entered into various arrangements for the purchase of electricity.  The total cost of purchases under these arrangements amounted to $200 million in 2004, $157.8 million in 2003 and $154.6 million in 2002.  These amounts relate to IPP contracts and do not include contractual commitments related to CL&P's standard offer.

Hydro-Quebec:  Along with other New England utilities, CL&P has entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada.  CL&P is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M expenses and capital costs of those facilities.  The total cost of these agreements amounted to $13.5 million in 2004, $14.4 million in 2003 and $14.8 million in 2002.

Yankee Companies FERC-Approved Billings:  CL&P has significant decommissioning and plant closure cost obligations to the Yankee Companies.  Each plant has been shut down and is undergoing decommissioning.  The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P.  These companies in turn pass these costs on to their customers through state regulatory commission-approved retail rates.  YAEC and MYAPC received FERC approval to collect all presently estimated decommissioning costs.  The table of estimated future annual costs below includes the decommissioning and closure costs for YAEC, MYAPC and CYAPC.

Estimated Future Annual Costs: The estimated future annual costs of CL&P’s significant long-term contractual arrangements are as follows:

(Millions of Dollars)	2005	2006	2007	2008	2009	Thereafter
VYNPC	$ 16.1	$ 16.9	$ 16.3	$ 16.5	$ 18.0	$     39.5
Electricity   Procurement   Contracts	193.0	194.5	198.1	188.4	159.9	889.6
Hydro-Quebec	14.1	13.9	13.0	11.7	11.2	123.2
Yankee   Companies   FERC-   Approved   Billings	60.4	53.5	48.4	41.4	39.2	38.6
Totals	$283.6	$278.8	$275.8	$258.0	$228.3	$1,090.9

E.

Deferred Contractual Obligations

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.  The revised estimate reflects the increases in the projected costs of spent fuel storage, and increased security and liability and property insurance costs, and the fact that CYAPC is now self-performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel in July 2003.  CL&P’s share of CYAPC's increase in decommissioning and plant closure costs is approximately $136 million.  On July 1, 2004, CYAPC filed with the FERC for recovery of these increased costs.  In the filing, CYAPC sought to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginnin g on January 1, 2005.  On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund, and scheduled hearings for May 2005.  In total, CL&P's estimated remaining decommissioning and plant closure obligation for CYAPC is $217.3 million at December 31, 2004.

On June 10, 2004, the DPUC and Office of Consumer Counsel (OCC) filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred.  On August 30, 2004, the FERC denied this petition.  On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition.  On October 29, 2004, the FERC issued an order granting further consideration regarding the DPUC's and OCC's petition for reconsideration.  No hearing date has been established for this reconsideration.

On February 22, 2005, the DPUC filed testimony with FERC.  In its filed testimony, the DPUC argues that approximately $215 million to $225 million of CYAPC’s requested increase is due to CYAPC’s imprudence in managing the decommissioning project while Bechtel was the contractor.  Therefore, the DPUC recommends a total disallowance of between $225 million to $234 million.  Hearings are scheduled to begin on June 1, 2005.  CL&P’s share of the DPUC’s recommended disallowance is between $78 million to $81 million.

CYAPC is currently in litigation with Bechtel over the termination of its decommissioning contract.  On June 13, 2003, CYAPC gave notice of the termination of its contract with Bechtel for the decommissioning of its nuclear power plant.  CYAPC terminated the contract due to Bechtel's incomplete and untimely performance and refusal to perform the remaining decommissioning work.  Bechtel has departed the site and the decommissioning responsibility has been transitioned to CYAPC, which has recommenced the decommissioning process.

On June 23, 2003, Bechtel filed a complaint against CYAPC asserting a number of claims and seeking a variety of remedies, including monetary and punitive damages and rescission of the contract.  Bechtel has since amended its complaint to add claims for wrongful termination.  On August 22, 2003, CYAPC filed its answer and counterclaims, including counts for breach of contract, negligent misrepresentation and breach of duty of good faith and fair dealing.  Discovery is currently underway and a trial has been scheduled for May 2006.  

In the prejudgment remedy proceeding before the Connecticut Supreme Court (the Court), Bechtel sought garnishment of the CYAPC decommissioning trust and related payments.  In October 2004, Bechtel and CYAPC entered into an agreement under which Bechtel waived its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CYAPC's real property in Connecticut and the escrowing of $41.7 million the sponsors are scheduled to pay to CYAPC through June 30, 2007 in respect to CYAPC's common equity.  This stipulation is subject to approval of the Court and would not be implemented until the Court found that such assets were subject to attachment.  CYAPC has contested the attachability of such assets.  The DPUC is an intervener in this proceeding.

Management cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of the increased CYAPC decommissioning costs.  Management believes that the costs have been prudently incurred and will ultimately be recovered from the customers of CL&P.  However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.  CL&P also cannot predict the timing and the outcome of the litigation with Bechtel.

The Yankee Companies also filed litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Nuclear Waste Policy Act of 1982 (the Act).  Under the Act, the DOE was to begin removing spent nuclear fuel from the nuclear plants of YAEC, MYAPC and CYAPC no later than January 31, 1998 in return for payments by each company into the nuclear waste fund.  No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies' plants.  YAEC, MYAPC and CYAPC collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates.  The wholesale utility customers in turn collect these payments from their retail electric customers.  The Yankee Companies' individual damage claims attributed to the government's breach totaling $548 million are specific to each plant and include incremental storage, security, construction and other costs through 2010, which is the earliest date the DOE projects that it will begin removing nuclear fuel.  The YAEC damage claim is $191 million, the MYAPC claim is $160 million and the CYAPC claim is $197 million.

The DOE trial ended on August 31, 2004 and a verdict has not been reached.  The current Yankee Companies' rates do not include an amount for recovery of damages in this matter.  Management can predict neither the outcome of this matter nor its ultimate impact on CL&P.

F.

NRG Energy, Inc. Exposures

CL&P has entered into transactions with NRG Energy, Inc. (NRG) and certain of its subsidiaries.  On May 14, 2003, NRG and certain of its subsidiaries filed voluntary bankruptcy petitions.  On December 5, 2003, NRG emerged from bankruptcy.  CL&P's NRG-related exposures as a result of these transactions relate to 1) the recovery of congestion charges incurred by NRG prior to the implementation of SMD on March 1, 2003, 2) the recovery of CL&P's station service billings from NRG and 3) the recovery of CL&P’s expenditures that were incurred related to an NRG subsidiary’s generating plant construction project that is now abandoned.  While it is unable to determine the ultimate outcome of these issues, management does not expect their resolution will have a material adverse effect on CL&P's consolidated financial condition or results of operations.

7.   Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:

Restricted Cash – LMP Costs:  The carrying amounts approximate fair value due to the short-term nature of this cash item.

Preferred Stock, Long-Term Debt and Rate Reduction Bonds:  The fair value of CL&P’s fixed-rate securities is based upon the quoted market price for those issues or similar issues.  Adjustable rate securities are assumed to have a fair value equal to their carrying value.  The carrying amounts of CL&P’s financial instruments and the estimated fair values are as follows:

	At December 31, 2004
(Millions of Dollars)	Carrying Amount	Fair Value
Preferred stock not subject to   mandatory redemption	$116.2	$   101.4
Long-term debt -
First mortgage bonds	419.8	470.1
Other long-term debt	634.2	652.6
Rate reduction bonds	995.2	1,074.9

	At December 31, 2003
(Millions of Dollars)	Carrying Amount	Fair Value
Preferred stock not subject to   mandatory redemption	$  116.2	$    87.5
Long-term debt -
First mortgage bonds	198.8	244.9
Other long-term debt	631.6	650.1
Rate reduction bonds	1,124.8	1,197.5

Other long-term debt includes $210.4 million and $207.7 million of fees and interest due for spent nuclear fuel disposal costs at December 31, 2004 and 2003, respectively.

Other Financial Instruments:  The carrying value of financial instruments included in current assets and current liabilities, including investments in securitizable assets, approximates their fair value.

8.   Leases  

CL&P has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, and office space.  The provisions of these lease agreements generally provide for renewal options.  Certain lease agreements contain contingent lease payments.  The contingent lease payments are based on various factors, such as, the commercial paper rate plus a credit spread or the consumer price index.

Capital lease rental payments charged to operating expense were $3 million in 2004, $3.1 million in 2003 and $3 million in 2002.  Interest included in capital lease rental payments was $1.8 million in 2004 and $2 million in 2003 and 2002.  Operating lease rental payments charged to expense were $17.7 million in 2004, $11.9 million in 2003 and $10.6 million in 2002.

Future minimum rental payments excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, at December 31, 2004 are as follows:

(Millions of Dollars)	Capital Leases	Operating Leases
2005	$ 2.6	$ 20.6
2006	2.5	19.4
2007	2.4	18.1
2008	2.1	14.4
2009	2.0	7.3
Thereafter	18.1	31.3
Future minimum lease payments	29.7	$111.1
Less amount representing interest	15.6
Present value of future minimum   lease payments	$14.1

9.   Dividend Restrictions

The Federal Power Act and the 1935 Act limit the payment of dividends by CL&P to its retained earnings balance.  

CL&P also has dividend restrictions imposed by its long-term debt agreements.  These restrictions limit the amount of retained earnings available for common dividends.  

The unsecured revolving credit agreement also limits dividend payments subject to the requirements that CL&P's total debt to total capitalization ratio does not exceed 65 percent.  

At December 31, 2004, retained earnings available for payment of dividends is restricted to $273 million.

10. Accumulated Other Comprehensive
       Income/(Loss)

The accumulated balance for each other comprehensive income/(loss) item is as follows:

(Millions of Dollars)	December 31, 2003	Current Period Change	December 31, 2004
Unrealized gains   on securities	$ 0.1	$     -	$   0.1
Minimum supplemental   executive retirement   pension liability   adjustments	(0.4)	(0.1)	(0.5)
Accumulated other   comprehensive   loss	$(0.3)	$(0.1)	$(0.4)

(Millions of Dollars)	December 31, 2002	Current Period Change	December 31, 2003
Unrealized   (losses)/gains   on securities	$(0.1)	$0.2	$ 0.1
Minimum supplemental   executive retirement   pension liability   adjustments	(0.3)	(0.1)	(0.4)
Accumulated other   comprehensive   (loss)/income	$(0.4)	$0.1	$(0.3)

The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:

(Millions of Dollars)	2004	2003	2002
Unrealized (losses)/gains   on securities	$-	$ (0.1)	$0.3
Minimum supplemental   executive retirement   pension liability   adjustments	-	-	-
Accumulated other   comprehensive   (loss)/income	$-	$ (0.1)	$0.3

11.  Preferred Stock Not Subject to
       Mandatory Redemption  

Details of preferred stock not subject to mandatory redemption are as follows:   

Description	December 31, 2004 Redemption Price	Shares Outstanding at December 31, 2004 and 2003	December 31,  2004           2003
		(Millions of Dollars)
$1.90 Series      of 1947	$52.50	163,912	$   8.2	$   8.2
$2.00 Series      of 1947	54.00	336,088	16.8	16.8
$2.04 Series      of 1949	52.00	100,000	5.0	5.0
$2.20 Series      of 1949	52.50	200,000	10.0	10.0
3.90% Series      of 1949	50.50	160,000	8.0	8.0
$2.06 Series E      of 1954	51.00	200,000	10.0	10.0
$2.09 Series F      of 1955	51.00	100,000	5.0	5.0
4.50% Series      of 1956	50.75	104,000	5.2	5.2
4.96% Series      of 1958	50.50	100,000	5.0	5.0
4.50% Series      of 1963	50.50	160,000	8.0	8.0
5.28% Series       of 1967	51.43	200,000	10.0	10.0
$3.24 Series G      of 1968	51.84	300,000	15.0	15.0
6.56% Series      of 1968	51.44	200,000	10.0	10.0
Totals			$116.2	$116.2

12.  Long-Term Debt   

Details of long-term debt outstanding are as follows:

At December 31,	2004	2003
	(Millions of Dollars)
First Mortgage Bonds:
8.50% Series C due 2024	$       -	$  59.0
7.875% Series D due 2024	139.8	139.8
4.800% Series A due 2014	150.0	-
7.875% Series B due 2034	130.0	-
Total First Mortgage Bonds	419.8	198.8
Pollution Control Notes:
5.85%-5.90%, fixed rate,     due 2016-2022	46.4	46.4
5.85%-5.95%, fixed rate tax     exempt, due 2028	315.5	315.5
Variable rate, tax exempt, due 2031	62.0	62.0
Total Pollution Control Notes	423.9	423.9
Total First Mortgage Bonds and   Pollution Control Notes	843.7	622.7
Fees and interest due for spent   nuclear fuel disposal costs	210.4	207.7
Less amounts due within one year	-	-
Unamortized premium and   discount, net	(1.2)	(0.3)
Long-term debt	$1,052.9	$830.1

There are no cash sinking fund requirements or debt maturities for the years 2005 through 2009.

Essentially, all utility plant of CL&P is subject to the liens of the company's first mortgage bond indenture.

CL&P has $315.5 million of pollution control notes secured by second mortgage liens on transmission assets, junior to the liens of their first mortgage bond indentures.

CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs) with bond insurance secured by the first mortgage bonds.  For financial reporting purposes, these first mortgage bonds would not be considered outstanding unless CL&P failed to meet its obligations under the PCRBs.  On October 1, 2003, CL&P fixed the interest rate on $62 million of variable-rate, tax-exempt notes for five years at 3.35 percent.  These notes mature in 2031.

13.  Income Tax Expense   

The components of the federal and state income tax provisions were charged/(credited) to operations as follows:

For  the Years   Ended December 31,	2004	2003	2002
	(Millions of Dollars)
Current income taxes:
Federal	$(50.6)	$ 115.0	$ 114.4
State	(6.2)	28.8	24.3
Total current	(56.8)	143.8	138.7
Deferred income taxes, net:
Federal	99.6	(88.7)	(58.6)
State	5.3	(34.5)	(16.5)
Total deferred	104.9	(123.2)	(75.1)
Investment tax credits, net	(2.6)	(2.5)	(3.3)
Total income tax expense	$ 45.5	$   18.1	$  60.3

A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:

For  the Years   Ended December 31,	2004	2003	2002
	(Millions of Dollars)
Expected federal income tax	$46.7	$30.5	$51.1
Tax effect of differences:
Depreciation	2.0	(0.3)	3.8
Amortization of  regulatory      assets	-	-	10.3
Investment tax credit     amortization	(2.6)	(2.5)	(3.4)
State income taxes,     net of federal benefit	(0.2)	(3.7)	5.1
Tax asset valuation     reserve adjustment	-	(5.5)	(1.3)
Property taxes	(1.0)	(0.3)	0.1
Allowance for doubtful accounts	(1.0)	1.7	(0.2)
Other, net	1.6	(1.8)	(5.2)
Total income tax expense	$45.5	$18.1	$60.3

14.  Segment Information  

Segment information related to the distribution and transmission businesses for CL&P for the years ended December 31, 2004, 2003, and 2002 is as follows:

For the Year Ended December 31, 2004
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$2,738.8	$  94.1	$2,832.9
Depreciation and   amortization	(238.8)	(15.4)	(254.2)
Other operating   expenses	(2,311.5)	(45.1)	(2,356.6)
Operating income	188.5	33.6	222.1
Interest expense, net of    AFUDC	(101.1)	(8.9)	(110.0)
Interest income	1.9	2.3	4.2
Other income/(loss), net	20.0	(2.8)	17.2
Income tax expense	(41.0)	(4.5)	(45.5)
Net income	$      68.3	$    19.7	$     88.0
Total assets  (1)	$ 5,316.3	$         -	$5,316.3
Cash flows for total  investments in plant	$    242.7	$  128.1	$  370.8

For the Year Ended December 31, 2003
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$2,627.0	$77.5	$2,704.5
Depreciation and   amortization	(299.8)	(13.9)	(313.7)
Other operating   expenses	(2,162.5)	(35.2)	(2,197.7)
Operating income	164.7	28.4	193.1
Interest expense, net of    AFUDC	(108.1)	(2.5)	(110.6)
Interest income	0.7	(0.1)	0.6
Other income/(loss), net	4.5	(0.5)	4.0
Income tax expense	(10.0)	(8.2)	(18.2)
Net income	$     51.8	$17.1	$     68.9
Total assets (1)	$5,206.9	$     -	$5,206.9
Cash flows for total  investments in plant	$   259.6	$63.5	$   323.1

(1) Information for segmenting total assets between distribution and transmission is not available at December 31, 2004 or December 31, 2003.

For the Year Ended December 31, 2002
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$2,428.5	$78.5	$2,507.0
Depreciation and   amortization	(269.5)	(13.6)	(283.1)
Other operating expenses	(1,948.7)	(30.4)	(1,979.1)
Operating income	210.3	34.5	244.8
Interest expense, net of    AFUDC	(119.5)	(1.5)	(121.0)
Interest income	1.5	-	1.5
Other income/(loss), net	22.0	(1.4)	20.6
Income tax expense	(61.1)	0.8	(60.3)
Net income	$   53.2	$32.4	$     85.6
Cash flows for total   investments in plant	$ 223.5	$39.1	$   262.6

15.  Reclassification of Previously Issued Financial Statements

Certain reclassifications of prior years’ data have been made to conform with the current year’s presentation.  These reclassifications are summarized in the following tables (in thousands):

	At December 31, 2003
	Previously  Reported	As Reclassified
Derivative assets - current	$   115,370	$   15,609
Derivative assets - long-term	-	99,761
	115,370	115,370
Derivative liabilities - current	54,566	5,061
Derivative liabilities - long-term	-	49,505
	54,566	54,566
Accumulated deferred income taxes	609,068	598,051
Other current liabilities	49,674	60,691
	$658,742	$658,742

Reclassifications to income statement amounts are as follows:

	For Year Ended December 31, 2003
	Previously Reported	As Reclassified
Amortization of regulatory assets, net	$ 98,670	$105,956
Income tax expense	25,421	18,135

	For Year Ended December 31, 2002
	Previously Reported	As Reclassified
Amortization of regulatory assets, net	$ 81,785	$  88,318
Income tax expense	66,866	60,333

Consolidated Quarterly Financial Data (Unaudited)
(Thousands of Dollars)	Quarter Ended (a)
2004	March 31	June 30	September 30	December 31
Operating Revenues	$748,690	$679,080	$725,532	$679,622
Operating Income	$  64,281	$  49,166	$  64,938	$  43,704
Net Income	$  27,613	$  18,645	$  23,074	$  18,684
2003
Operating Revenues	$705,916	$615,268	$797,896	$585,444
Operating Income	$  67,148	$  36,654	$  71,998	$  18,086
Net Income	$  26,722	$    6,064	$  30,431	$    5,691

Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars)	2004	2003	2002	2001	2000
Operating Revenues	$2,832,924	$2,704,524	$2,507,036	$2,646,123	$2,935,922
Net Income	88,016	68,908	85,612	109,803	148,135
Cash Dividends on Common Stock	47,074	60,110	60,145	60,072	72,014
Property, Plant and Equipment, net (b)	2,824,877	2,561,898	2,332,693	2,029,173	1,754,176
Total Assets (c)	5,316,258	5,206,894	4,786,083	4,727,727	4,764,198
Rate Reduction Bonds	995,233	1,124,779	1,245,728	1,358,653	-
Long-Term Debt (d)	1,052,891	830,149	827,866	824,349	1,232,688
Preferred Stock Not Subject to Mandatory Redemption	116,200	116,200	116,200	116,200	116,200
Obligations Under Capital Leases (d)	14,093	14,879	15,499	16,040	129,869

Consolidated Statistics (Unaudited)
	2004	2003	2002	2001	2000
Revenues:  (Thousands)
Residential	$1,155,492	$1,151,707	$1,028,425	$   991,946	$  965,528
Commercial	939,579	960,678	874,713	855,348	823,130
Industrial	275,730	290,526	274,228	285,479	285,877
Other Utilities	295,833	322,955	271,484	420,664	745,399
Streetlighting and Railroads	31,897	35,358	33,788	33,356	34,967
Non-franchised Sales	-	-	-	-	1,390
Miscellaneous	134,393	(56,700)	24,398	59,330	79,631
Total	$2,832,924	$2,704,524	$2,507,036	$2,646,123	$2,935,922
Sales:  (kWh - Millions)
Residential	10,305	10,359	9,699	9,340	9,084
Commercial	9,922	9,829	9,644	9,460	9,037
Industrial	3,623	3,630	3,707	3,850	4,000
Other Utilities	5,375	5,885	6,281	9,709	19,713
Streetlighting and Railroads	298	298	292	286	286
Non-franchised Sales	-	-	-	-	59
Total	29,523	30,001	29,623	32,645	42,179
Customers:  (Average)
Residential	1,071,249	1,058,247	1,048,096	1,050,633	1,022,466
Commercial	108,865	104,750	103,408	95,782	92,303
Industrial	4,078	3,989	4,035	4,028	3,983
Other	2,694	2,643	2,768	2,791	2,799
Total	1,186,886	1,169,629	1,158,307	1,153,234	1,121,551
Average Annual Use Per      Residential Customer (kWh)	9,620	9,790	9,244	8,884	8,976
Average Annual Bill Per   Residential Customer	$1,078.40	$1,089.63	$979.86	$943.48	$954.15
Average Revenue Per kWh:
Residential	11.21¢	11.13¢	10.60¢	10.62¢	10.63¢
Commercial	9.47	9.77	9.07	9.04	9.11
Industrial	7.61	8.00	7.40	7.42	7.15

(a) Certain reclassifications of prior years' data have been made to conform with the current year's presentation.

(b) Amount includes construction work in progress.

(c) Total assets were not adjusted for cost of removal prior to 2002.

(d) Includes portions due within one year.