Western Massachusetts Electric 10K 2004 Annual report | SEC Filing

2004 Annual Report

Public Service Company of New Hampshire

Index

Contents

Page

Management's Discussion and Analysis of Financial

Condition and Results of Operations

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets

14-15

Consolidated Statements of Income

Consolidated Statements of Comprehensive Income

Consolidated Statements of Common Stockholder's Equity

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

Consolidated Quarterly Financial Data (Unaudited)

Selected Consolidated Financial Data (Unaudited)

Consolidated Statistics (Unaudited)

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:

Public Service Company of New Hampshire (PSNH or the company) reported earnings of $46.6 million in 2004 compared with earnings of $45.6 million in 2003 and $62.9 million in 2002.

Regulatory Items:

PSNH resolved a number of outstanding regulatory issues. Among the most important items were:

On September 2, 2004, the New Hampshire Public Utilities Commission (NHPUC) approved the negotiated settlement of the PSNH rate case that was filed in 2003. The settlement agreement resulted in an annualized delivery rate increase of $3.5 million beginning October 1, 2004 and approval of another rate increase of $10 million on June 1, 2005.

On September 24, 2004, PSNH filed a petition with the NHPUC requesting a change in the transition energy service(TS) rate for residential and small commercial customers and the default energy service rate (TS/DS) for large commercial and industrial customers for the period February 1, 2005 through January 31, 2006. PSNH files for updated TS/DS rates periodically to ensure timely recovery of its costs. The NHPUC issued its order approving PSNH's proposed TS/DS rate of $0.0649 per kWh on January 28, 2005.

In October 2004, PSNH received the approvals necessary to begin construction related to the conversion of one of three 50-megawatt units at the coal-fired Schiller Station to burn wood.

Liquidity:

During 2004, PSNH issued $50 million of 10-year first mortgage bonds at a fixed interest rate of 5.25 percent. The debt was issued primarily to repay short term debt and fund PSNH’s capital expenditure program.

PSNH’s capital expenditures totaled $143.6 million in 2004, compared with $105.4 million in 2003 and $107 million in 2002. The increase was primarily the result of higher distribution and generation capital expenditures. PSNH projects capital expenditures of approximately $150 million in 2005.

PSNH’s net cash flows from operations totaled $192.4 million in 2004, compared with $82 million in 2003 and $323.2 million in 2002.

Overview

PSNH is a wholly owned subsidiary of Northeast Utilities (NU), NU’s other subsidiaries include The Connecticut Light and Power Company, Western Massachusetts Electric Company, Yankee Energy System, Inc., North Atlantic Energy Corporation (NAEC), Select Energy, Inc., Northeast Generation Company, Northeast Generation Services Company, and Select Energy Services, Inc.

PSNH earned $46.6 million in 2004, compared with $45.6 million in 2003 and $62.9 million in 2002. PSNH's earnings were higher primarily due to a lower effective tax rate and an increase in retail sales of 3.1 percent. The lower effective tax rate and increase in sales were largely offset by higher operating expenses and higher pension expense. The lower effective tax rate was due to other adjustments to tax expense totaling a positive $5.4 million recorded in the third quarter of 2004.

Included in PSNH's earnings are the results of the transmission business. PSNH's transmission business earnings were $6.8 million in 2004 as compared to $7.3 million in 2003.

PSNH’s revenues for 2004 increased to $968.7 million from $888.2 million in 2003 due to higher delivery revenues as a result of higher rates, higher transition energy service revenues and the acquisition of Connecticut Valley Electric Company.

Future Outlook

Management projects PSNH's earnings to decrease in 2005 as compared with 2004. PSNH's 2005 earnings are expected to benefit from an increase in rates due to the rate case settlement approved on September 2, 2004, offset by an increase in pension and medical expenses and higher taxes.

The key to PSNH maintaining an adequate level of liquidity will be its continuing high level of recovery of regulatory assets in 2005 and 2006. A high level of recovery will allow PSNH to cover a majority of the costs associated with its larger capital expenditure program.

Strategic Overview

PSNH has identified investment requirements and expects to invest more than $600 million in its regulated electric infrastructure from 2005 through 2009.

Based on current projections, management expects that the need to invest in infrastructure to meet reliability requirements and customer growth will cause PSNH’s distribution and generation rate base to rise from $700 million in 2004 to nearly $1 billion by the end of 2009. Based on currently projected expenditures and capital project completion dates, management expects that the same factors will increase PSNH’s transmission rate base from approximately $120 million in 2004 to approximately $180 million by the end of 2009.

Liquidity

Cash flows from operations increased by $110.4 million from $82 million in 2003 to $192.4 million in 2004. The increase in cash flows from operations was primarily the result of an increase in amortization of regulatory assets and lower income taxes paid in 2004 than 2003.

Capital expenditures described herein are cash capital expenditures and exclude cost of removal, AFUDC and the capitalized portion of pension income. PSNH’s capital expenditures totaled $143.6 million in 2004, compared with $105.4 million in 2003 and $107 million in 2002. The increase in capital expenditures was primarily the result of higher distribution capital expenditures, which totaled $115.4 million in 2004 compared with $78.4 million in 2003 and $90.8 million in 2002. The company projects capital expenditures of approximately $621 million over the five-year period from 2005 through 2009, including approximately $150 million in 2005. Capital spending projections are highly dependent on regulatory approval of major projects.

During 2004, Standard & Poor’s (S&P) reduced the outlook on all PSNH securities it rates to "negative" from "stable." In February 2005, Moody's Investors Service (Moody's) affirmed with no change the ratings for PSNH. All ratings of PSNH securities remain investment grade.

On November 8, 2004, PSNH entered a 5-year unsecured revolving credit facility, under which PSNH is able to borrow up to $100 million on a short-term basis. PSNH had $10 million in borrowings outstanding under this credit facility at December 31, 2004 and 2003. For more information

regarding this revolving credit facility, see Note 2, "Short-Term Debt" to the consolidated financial statements.

On July 22, 2004, PSNH issued $50 million of 10-year first mortgage bonds at a fixed interest rate of 5.25 percent. Proceeds were used to repay short-term debt and fund PSNH’s capital expenditure program. In October 2004, PSNH received the approvals necessary to begin the construction related to the conversion of one of the coal-fired units at Schiller Station to burn wood. The NHPUC approved the project, but the NHPUC's approval has been appealed to the New Hampshire Supreme Court. This project is expected to cost approximately $75 million.

Nuclear Decommissioning and Plant Closure Costs

Connecticut Yankee Atomic Power Company (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 the Bechtel Power Company (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, 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. PSNH's share of CYAPC's increase in decommissioning and plant closure costs is approximately $20 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 beginning on Janu ary 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, PSNH's estimated remaining decommissioning and plant closure obligation for CYAPC is $31.5 million at December 31, 2004.

On June 10, 2004, the Connecticut Department of Utility Control (DPUC) and Office of Consumer Counsel of the state of Connecticut (OCC) filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including PSNH 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 being on June 1, 2005. PSNH’s share of the DPUC’s recommended disallowance is between $11 million to $12 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 PSNH. 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 PSNH.

Business Development and Capital Expenditures

In 2004, PSNH’s capital expenditures totaled $143.6 million, compared with $105.4 million in 2003 and $107 million in 2002. PSNH’s capital expenditures are projected to increase to approximately $150 million in 2005, primarily as a result of the conversion of one of three 50 megawatt units at the coal-fired Schiller Station to burn wood (Northern Wood Power Project). Construction of the $75 million Northern Wood Power Project has begun and is expected to be completed by late 2006. The NHPUC’s 2004 approval of the project has been appealed to the New Hampshire Supreme Court brought by some of New Hampshire’s existing wood-fired generating plant owners. Management does not believe that the appeal will negatively affect PSNH’s ability to complete the Northern Wood Power Project.

In addition to the Northern Wood Power Project, PSNH’s capital spending in 2005 will be driven in part by its agreement in its 2004 rate case settlement to invest approximately $60 million in its capital improvement program.

Transmission Access and FERC Regulatory Changes

PSNH 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 New England Independent System Operator (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 Return on Equity (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 February 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 PSNH’s, wholesale transmission revenues are collected through a combination of the RNS tariff and LNS tariff. PSNH’s LNS tariff is reset on June 1st of each year to coincide with the change in RNS rates. Additionally, PSNH’s LNS tariff provides for a true-up to actual costs, which ensures that NU 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 PSNH 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 PSNH’s earnings by $0.2 million in 2004. 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, PSNH 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 PSNH’s transmission businesses’ revenue is from charges to PSNH’s electric distribution business. PSNH recovers transmission charges through rates charged to its retail customers. The June 1, 2005 PSNH retail rate increase includes revenues to recover expected transmission costs. PSNH 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. PSNH will incur LICAP charges . These costs will be recovered from PSNH’s customers.

Delivery Rate Case: PSNH's delivery rates were fixed, effective May 1, 2001, by the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement) until February 1, 2004. Consistent with the requirements of the Restructuring Settlement and state law, PSNH filed a delivery service rate case and tariffs with the NHPUC on December 29, 2003 to increase electricity delivery rates by approximately $21 million, or 2.6 percent, effective February 1, 2004.

On July 14, 2004, PSNH filed with the NHPUC a revenue requirements settlement agreement among several parties, including the NHPUC staff and the Office of Consumer Advocate (OCA). The terms of the proposed settlement agreement allowed for increases in PSNH's delivery rates totaling $3.5 million annually, effective prospectively beginning October 1, 2004, and an incremental $10 million annual increase effective prospectively on June 1, 2005, for a total rate increase of $13.5 million. On July 29, 2004, PSNH filed with the NHPUC a rate design settlement agreement among several parties, including the NHPUC staff. These proposed revenue requirements and rate design settlement agreements together resolved all delivery service rate case issues. On September 2, 2004, the NHPUC issued an order approving both settlement agreements, and new delivery service rates went into effect on October&n bsp;1, 2004.

Transition Energy Service and Default Energy Service: In accordance with the Restructuring Settlement and state law, PSNH files for updated TS/DS rates periodically to ensure timely recovery of its costs. The TS/DS rate recovers PSNH's generation and purchased power costs, including a return on PSNH's generation investment. PSNH defers for future recovery or refund any difference between its TS/DS revenues and the actual costs incurred.

On September 24, 2004, PSNH filed a petition with the NHPUC requesting a change in the TS/DS rate for the period February 1, 2005 through January 31, 2006. In December 2004, PSNH petitioned for a TS/DS rate of $0.0649 per kWh based on updated market information. The NHPUC issued its order approving a TS/DS rate of $0.0649 per kWh on January 28, 2005. This TS/DS rate includes an 11 percent ROE on PSNH's generation assets, which is subject to further review by the NHPUC.

SCRC Reconciliation Filings: The SCRC allows PSNH to recover its stranded costs. On an annual basis, PSNH files with the NHPUC a SCRC reconciliation filing for the preceding calendar year. This filing includes the reconciliation of stranded cost revenues billed with stranded costs, and TS/DS revenues billed with TS/DS costs. The NHPUC reviews the filing, including a prudence review of PSNH's generation operations. The cumulative deferral of SCRC revenues in excess of costs was $208.6 million at December 31, 2004. This cumulative deferral will decrease the amount of non-securitized stranded costs that will have to be recovered from PSNH's customers in the future from $411.3 million to $202.7 million.

The 2003 SCRC reconciliation filing was filed with the NHPUC on April 30, 2004, and a stipulation and settlement agreement between PSNH, the Office of Consumer Advocate and NHPUC staff was filed with the NHPUC on October 4, 2004. Under the terms of the settlement agreement, no costs related to the recovery of stranded costs or the cost of providing TS were disallowed, and the NHPUC staff agreed to accept the 2003 SCRC filing without change. On October 29, 2004, the NHPUC issued an order accepting the settlement agreement as filed.

The 2004 SCRC reconciliation filing is expected to be filed with the NHPUC by May 2, 2005. Management does not expect the NHPUC's review of the 2004 SCRC filing to have a material impact on PSNH's net income or financial position.

The SCRC and TS/DS rate mechanisms currently reconcile accrued expenses with billed revenues on a monthly basis. On May 2, 2005, PSNH expects to file its annual 2004 SCRC and TS/DS reconciliation that will include a request to include unbilled revenues as part of the reconciliation process. This request will allow for the reconciliation of revenues on an accrual basis with the current accrued expenses recovered through the SCRC and TS/DS rate mechanisms, consistent with accrual accounting. At December 31, 2004, the PSNH unbilled revenue balance related to SCRC and TS/DS was $11.7 million and $16.7 million, respectively. If approved, this change will allow for the inclusion of accrued unbilled revenue balances in the recovery of SCRC and TS/DS costs. Management believes that the unbilled revenue balance related to SCRC and TS/DS is probable of being recovered from PSNH's customers.

Wholesale Distribution Rate Case: PSNH is planning to file a wholesale distribution rate case with the FERC in late March 2005. This FERC filing is necessary due to the reclassification of certain assets from PSNH's transmission business to distribution business. PSNH plans to file a revenue requirements analysis in order to recover certain delivery costs arising from the provision of wholesale delivery service to another New Hampshire utility.

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 PSNH. 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, PSNH's consolidated financial statements include all subsidiaries upon which control is maintained and all variable interest entities (VIE) for which PSNH 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.

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

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

Revenue Recognition: PSNH's retail revenues are based on rates approved by the NHPUC. 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 NHPUC.

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.

PSNH 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 over-collections 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 PSNH's wholesale transmission revenues are collected through a combination of the New England RNS tariff and PSNH'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 PSNH's wholesale transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates.

The settlement of wholesale non-trading derivative contracts for the sale of electricity by PSNH that are related to customers' needs are recorded in operating expenses. For further information regarding the accounting for these contracts, see Note 1F, "Summary of Significant Accounting Policies - Derivative Accounting," to the consolidated financial statements.

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 PSNH's consolidated financial statements as adjustments to that estimate could significantly impact operating revenues and earnings.

PSNH 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 PSNH 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 $3.3 million.

Derivative Accounting: Effective January 1, 2001, PSNH adopted Statement of Financial Accounting Standards (SFAS) No. 133, as amended.

Many of PSNH’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 PSNH’s consolidated net income.

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 PSNH 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, 2003 as derivative assets and liabilities with offsetting amounts recorded as regulatory liabilities and assets because the contracts were part of providing reg ulated electric 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 PSNH’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, management applied its conclusion on net or gross reporting to all periods presented to enhance comparability.

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

Regulatory Accounting: The accounting policies of PSNH 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 generation, transmission and distribution businesses of PSNH continue to be cost-of-service rate regulated, and management believes the application of SFAS No. 71 to 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 the company 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 PSNH'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, PSNH records regulatory assets before approval for recovery has been received from the NHPUC. 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 NHPUC 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 NHPUC can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on PSNH’s consolidated financial statements. Management believes it is probable that PSNH will recover the regulatory assets that have been recorded.

Pension and Postretirement Benefits Other Than Pensions (PBOP): PSNH participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular PSNH employees. PSNH 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 PSNH's consolidated financial statements.

Results: Pre-tax periodic pension expense for the Pension Plan totaled $12.4 million, $6.8 million and $0.6 million for the years ended December 31, 2004, 2003 and 2002, respectively.

The pre-tax net PBOP Plan cost totaled $7.5 million, $6.2 million and $5.3 million for the years ended December 31, 2004, 2003 and 2002, respectively.

There were no settlements, curtailments or special termination benefits for the Pension Plan or the PBOP Plan for 2004, 2003 or 2002.

Long-Term Rate of Return Assumptions: In developing the expected long-term rate of return assumptions, PSNH evaluated input from actuaries and consultants, as well as long-term inflation assumptions and PSNH's historical 20-year compounded return of approximately 11 percent. PSNH's expected long-term rates of return on assets is based on certain target asset allocation assumptions and expected long-term rates of return. PSNH believes that 8.75 percent is a reasonable long-term rate of return on Pension Plan and PBOP Plan assets for 2004. PSNH 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
	2003 and 2004		2003 and 2004
	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. PSNH 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: PSNH bases the actuarial determination of Pension Plan and PBOP Plan 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 $5.7 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 $57.8 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 $52.1 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 $9.7 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 $34.8 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 $25.1 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 Investors Service and Standard and Poor'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 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, PSNH estimates that expected contributions to and forecasted expense for the Pension Plan and PBOP Plan will be as follows (in millions):

Pension Plans Postretirement Plan
Year	Expected Contributions	Forecasted Expense	Expected Contributions	Forecasted Expense
2005	$ -	$17.7	$9.1	$9.1
2006	$ -	$19.6	$8.5	$8.5
2007	$ -	$19.3	$7.1	$7.1

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	$ 1.0	$ 1.1	$0.1	$0.2
Lower discount rate	2.2	1.9	0.2	0.2
Lower compensation increase	$(0.9)	$(1.0)	N/A	N/A

Plan Assets: The market-related value of the Pension Plan assets has increased from $191.9 million at December 31, 2003 to $201.6 million at December 31, 2004. The projected benefit obligation (PBO) for the Pension Plan has increased from $289 million at December 31, 2003 to $323.9 million at December 31, 2004. These changes have increased the underfunded status of the Pension Plan on a PBO basis from an underfunded position of $97.1 million at December 31, 2003 to an underfunded position of $122.3 million at December 31, 2004. The PBO includes expectations of future employee compensation increases. The accumulated benefit obligation (ABO) of the Pension Plan was $69.1 million more than Pension Plan assets at December 31, 2004 and $51.7 million more than Pension Plan assets at December 31, 2003. The ABO is the obligation for employee minimum liability.

Total Pension Plan assets on an NU consolidated basis were approximately $225 million and approximately $240 million more than the ABO at December 31, 2004 and 2003, respectively. If the ABO on an NU consolidated basis exceeds Pension Plan assets at a future plan measurement date, NU will record an additional minimum liability of which PSNH will be allocated its proportionate share. PSNH has not made employer contributions since 1991.

The value of PBOP Plan assets has increased from $29.7 million at December 31, 2003 to $34.6 million at December 31, 2004. The benefit obligation for the PBOP Plan has increased from $66.8 million at December 31, 2003 to $79.7 million at December 31, 2004. These changes have increased the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $37.1 million at December 31, 2003 to $45.1 million at December 31, 2004. PSNH 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 $0.1 million in 2004 and 2003.

Income Taxes: Income tax expense is calculated each year in each of the jurisdictions in which PSNH operates. This process involves estimating PSNH'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 PSNH's consolidated balance sheets. Adjustments made to income taxes could significantly affect PSNH'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 and liabilities an d valuation allowances.

PSNH 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, PSNH has established a regulatory asset. The regulatory asset amounted to $37.5 million and $44.2 million at December 31, 2004 and 2003, respectively. Regulatory agencies in certain jurisdictions in which PSNH 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 on 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 rates 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 11, "Income Tax Expense."

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 PSNH’s income tax returns. The income tax returns were filed in the fall of 2004 for the 2003 tax year, and PSNH 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 PSNH's consolidated financial statements absent timely rate relief.

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 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 regulation s 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.

Under current rate-making policy, PSNH has a regulatory recovery mechanism in place for environmental costs. Accordingly, regulatory assets have been recorded for certain of PSNH’s environmental liabilities. As of December 31, 2004 and 2003, $6.1 million and $7.6 million, respectively, have been recorded as regulatory assets on the accompanying consolidated balance sheets.

Capital expenditures related to environmental matters are expected to total approximately $67.9 million in aggregate for the years 2005 through 2009. Of the $67.9 million, approximately $55 million relates to the conversion of a 50 megawatt oil and coal burning unit at Schiller Station to a wood burning unit to, among other things, provide a reduction in air emissions at the plant.

Asset Retirement Obligations: PSNH 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 PSNH’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 PSNH 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 PSNH for AROs that PSNH 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 interp retation on PSNH.

Under SFAS No. 71, regulated utilities, including PSNH, 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 $87.6 million and $88 million, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.

Special Purpose Entities: During 2001 and 2002, to facilitate the issuance of rate reduction bonds intended to finance certain stranded costs, PSNH established two special purpose entity's: PSNH Funding LLC and PSNH Funding LLC 2 (the funding companies). The funding companies were created as part of a state-sponsored securitization program. The funding companies are restricted from engaging in non-related activities and are required to operate in a manner intended to reduce the likelihood that they would be included in PSNH’s bankruptcy estate if it ever became involved in a bankruptcy proceeding. The funding companies and the securitization amounts are consolidated in the accompanying consolidated financial statements.

Other Matters

Commitments and Contingencies: For further information regarding other commitments and contingencies, see Note 5, "Commitments and Contingencies," to the consolidated financial statements.

Contractual Obligations and Commercial Commitments: Information regarding PSNH’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)

$ 10.0

$ -

Long-term debt^(a)

457.2

Estimated interest
payments on
existing long-
term debt

18.8

199.5

Capital
leases^(b)(c)

0.5

0.4

0.2

Operating
leases^(c)(d)

6.6

6.1

5.1

3.9

1.8

3.8

Required funding
of other post-

retirement benefit

obligations

9.1

8.5

7.1

5.4

3.9

N/A

Long-term
contractual
arrangements^(c)(d)

190.1

157.6

76.0

49.0

48.6

300.8

Totals

$235.1

$191.4

$107.2

$77.3

$73.1

$961.3

^(a) Included in PSNH's debt agreements are usual and customary positive, negative and financial covenants. Non-compliance with certain covenants, for example the 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 $0.6 million.

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

^(d) Amounts are not included on PSNH's consolidated balance sheets.

Rate reduction bond amounts are non-recourse to PSNH, have no required payments over the next five years and are not included in this table. For further information regarding PSNH’s contractual obligations and commercial commitments, see the Consolidated Statements of Capitalization and related footnotes, and Note 2 "Short-Term Debt," Note 5C "Commitments and Contingencies - Long-Term Contractual Arrangements," Note 7 "Leases," and Note 10, "Long-Term Debt" to the consolidated financial statements.

Forward Looking Statements: This discussion and analysis includes statements concerning NU'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 included in t he forward looking statements include, but are not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, expiration or initiation of significant energy supply contracts, changes in levels of capital expenditures, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, effectiveness of 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 and close out natural gas positions at anticipated margins, obtaining new contracts at anticipated volumes and margins, terrorist attacks on domestic energy facilities and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our repo rts to the Securities and Exchange Commission. 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 PSNH's web site at www.psnh.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	$81	9%	$(59)	(6)%

Operating Expenses:
Fuel, purchased and net interchange power	10	3	115	40
Other operation	23	17	13	11
Maintenance	1	1	1	1
Depreciation	2	5	2	6
Amortization of regulatory assets, net	58	(a)	(158)	(81)
Amortization of rate reduction bonds	4	9	(3)	(6)
Taxes other than income taxes	2	7	(1)	(2)
Total operating expenses	100	13	(31)	(4)
Operating (Loss)/Income	(19)	(15)	(28)	(18)
Interest expense, net	1	1	(4)	(8)
Other income/(loss), net	4	80	(4)	(a)
Income before income tax expense	(16)	(21)	(28)	(27)
Income tax expense	(17)	(56)	(11)	(26)
Net Income	$ 1	2%	$ (17)	(27)%

(a) Percent greater than 100.

Operating Revenues

Operating revenues increased $81 million in 2004 compared with the same period of 2003 primarily due to higher distribution retail revenue ($93 million) and higher transmission revenue ($6 million), partially offset by lower wholesale revenue ($19 million). Distribution retail revenue increased primarily due to higher transition service energy rates ($67 million) and higher sales volumes ($28 million). The CVEC acquisition increased sales and represents $18 million of the revenue increase. Retail kilowatt-hour (kWh) sales increased by 3.1 percent in 2004. Transmission revenues were higher primarily due to the October 2003 implementation of the FERC approved transmission rate increase. The regulated wholesale revenue decrease is primarily due to a lower number of wholesale transactions.

Operating revenues decreased $59 million in 2003 compared with the same period of 2002 primarily due to lower regulated wholesale revenues resulting from the impact of less owned generation since the sale of Seabrook ($114 million), partially offset by higher retail revenues ($56 million). Retail revenues were higher primarily due to higher retail sales volumes ($37 million) and higher TS revenues. Retail kWh sales increased 4.7 percent for the year 2003.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power increased $10 million primarily due to higher fossil fuel costs ($9 million) as a result of higher fuel prices.

Fuel, purchased and net interchange power expense increased $115 million in 2003 primarily due to the absence of the 2002 gain on the sale of utility plant resulting from the sale of Seabrook recorded on NAEC’s books, which was transferred to PSNH through the Seabrook Power Contracts ($167 million), partially offset by lower fuel expense resulting from lower regulated wholesale transactions.

Other Operation

Other operation expenses increased $23 million in 2004 primarily due to higher retail transmission expenses which are collected through retail delivery rates ($7 million), higher fossil generation expense ($6 million), and higher administrative expenses ($10 million) primarily due to higher pension and medical costs.

Other operation expenses increased $13 million in 2003 primarily due to higher pension costs ($8 million) and higher conservation and customer assistance programs expense ($8 million), partially offset by lower fossil generation expense ($2 million).

Maintenance

Maintenance expense increased $1 million in 2004 primarily due to higher tree trimming and substation maintenance ($1 million) and higher transmission station and overhead line maintenance ($1 million), partially offset by lower fossil generation expenses ($1 million), mainly due to a higher level of maintenance overhaul expenses in 2003.

Maintenance expense increased $1 million in 2003 primarily due to higher substation and distribution maintenance ($2 million), partially offset by transmission overhead line maintenance ($1 million).

Depreciation

Depreciation increased $2 million in 2004 primarily due to higher plant balances.

Depreciation increased $2 million in 2003 primarily due to additions to distribution, generation, and general plant assets.

Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $58 million primarily due to an acceleration in the recovery of PSNH’s non-securitized stranded costs. The acceleration of non-securitized stranded cost recovery was possible due to the positive reconciliation of stranded costs revenues and stranded cost expense, which also includes net TS costs.

Amortization of regulatory assets, net decreased $158 million in 2003 primarily due to the 2002 amortization of stranded costs upon thesale of Seabrook ($167 million), partially offset by an increase in the recovery of stranded costs ($4 million) resulting from the SCRC reconciliation of stranded cost revenues against actual stranded costs.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $4 million as a result of the repayment of additional principal.

Amortization of rate reduction bonds decreased $3 million in 2003 due to the repayment of principal and associated reduction of securitized regulatory assets.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $2 million in 2004 primarily due to higher property tax ($1 million) and higher federal payroll taxes ($1 million).

Taxes other than income taxes decreased $1 million in 2003 primarily due to lower property tax.

Interest Expense, Net

Interest expense, net increased $1 million in 2004 primarily due to the issuance of $50 million of 10-year first mortgage bonds in July 2004, partially offset by lower interest on rate reduction bonds as a result of lower debt levels.

Interest expense, net decreased $4 million in 2003 due to lower interest on rate reduction bonds as a result of lower debt levels ($1 million) and lower rates.

Other Income/(Loss), Net

Other income/(loss), net increased $4 million in 2004 primarily due to an earned C&LM incentive ($2 million) and higher gains on the disposition of property ($1 million).

Other income/(loss), net decreased $4 million in 2003 primarily due to increased service fees associated with rate reduction bonds and lower gains on the disposition of property in 2003.

Income Tax Expense

Income tax expense decreased $17 million in 2004 primarily due to lower pre-tax earnings and a lower effective tax rate. The lower effective tax rate resulted from other adjustments to tax expense totaling $5 million and the unitary impact on state income tax expense.

Income tax expense decreased $11 million in 2003 primarily as a result of lower book taxable income as compared to 2002.

Company Report

Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Public Service Company of New Hampshire 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

Public Service Company of New Hampshire:

We have audited the accompanying consolidated balance sheets of Public Service Company of New Hampshire and subsidiaries (a New Hampshire 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 Public Service Company of New Hampshire 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

Hartford, Connecticut

March 16, 2005

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


At December 31,	2004	2003
	(Thousands of Dollars)
ASSETS

Current Assets:
Cash	$ 4,855	$ 2,737
Special deposits	-	30,104
Receivables, less provision for uncollectible
accounts of $1,764 in 2004 and $1,590 in 2003	75,019	67,121
Accounts receivable from affiliated companies	34,341	11,291
Unbilled revenues	39,397	39,220
Taxes receivable	4,498	-
Fuel, materials and supplies, at average cost	52,479	47,068
Derivative assets - current	-	1,510
Prepayments and other	11,065	9,315
	221,654	208,366

Property, Plant and Equipment:
Electric utility	1,627,174	1,517,513
Other	5,675	5,707
	1,632,849	1,523,220
Less: Accumulated depreciation	664,336	635,029
	968,513	888,191
Construction work in progress	63,190	37,401
	1,031,703	925,592

Deferred Debits and Other Assets:
Regulatory assets	900,115	969,434
Other	59,227	67,789
	959,342	1,037,223

Total Assets	$ 2,212,699	$ 2,171,181

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

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


At December 31,	2004	2003
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to banks	$ 10,000	$ 10,000
Notes payable to affiliated companies	20,400	48,900
Accounts payable	51,786	48,408
Accounts payable to affiliated companies	38,591	13,911
Accrued taxes	-	1,914
Accrued interest	11,799	10,894
Unremitted rate reduction bond collections	7,880	11,051
Derivative liabilities - current	-	1,414
Other	12,629	17,914
	153,085	164,406

Rate Reduction Bonds	428,769	472,222

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	311,998	337,206
Accumulated deferred investment tax credits	1,625	2,096
Deferred contractual obligations	54,459	64,237
Regulatory liabilities	323,707	272,579
Accrued pension	57,199	44,766
Other	24,968	26,124
	773,956	747,008
Capitalization:
Long-Term Debt	457,190	407,285

Common Stockholder's Equity:
Common stock, $1 par value - authorized
100,000,000 shares; 301 shares outstanding
in 2004 and 2003	-	-
Capital surplus, paid in	156,532	156,555
Retained earnings	243,277	223,822
Accumulated other comprehensive loss	(110)	(117)
Common Stockholder's Equity	399,699	380,260
Total Capitalization	856,889	787,545


Commitments and Contingencies (Note 5)


Total Liabilities and Capitalization	$ 2,212,699	$ 2,171,181

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

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME


For the Years Ended December 31,	2004	2003	2002
	(Thousands of Dollars)


Operating Revenues	$ 968,749	$ 888,186	$ 947,178

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	414,687	404,431	289,713
Other	161,616	138,637	125,220
Maintenance	65,620	64,872	64,146
Depreciation	45,662	43,322	40,941
Amortization of regulatory assets, net	95,436	37,861	196,246
Amortization of rate reduction bonds	43,764	40,040	42,714
Taxes other than income taxes	35,805	33,407	34,226
Total operating expenses	862,590	762,570	793,206
Operating Income	106,159	125,616	153,972

Interest Expense:
Interest on long-term debt	17,441	15,408	16,752
Interest on rate reduction bonds	26,901	29,081	30,499
Other interest	1,197	727	1,874
Interest expense, net	45,539	45,216	49,125
Other Loss, Net	(986)	(5,003)	(1,671)
Income Before Income Tax Expense	59,634	75,397	103,176
Income Tax Expense	12,993	29,773	40,279
Net Income	$ 46,641	$ 45,624	$ 62,897

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income	$ 46,641	$ 45,624	$ 62,897
Other comprehensive income/(loss), net of tax:
Unrealized gains/(losses) on securities	76	128	(620)
Minimum supplemental executive retirement
pension liability adjustments	(69)	(140)	109
Other comprehensive income/(loss), net of tax	7	(12)	(511)
Comprehensive Income	$ 46,648	$ 45,612	$ 62,386

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

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY



	Common Stock						Accumulated
				Capital Surplus,	Retained	Other Comprehensive
	Shares	Amount		Paid In	Earnings	Income/(Loss)		Total
			(Thousands of Dollars, except share information)
Balance at January 1, 2002	388	$ -		$ 165,000	$ 176,419	$ 406		$ 341,825

Net income for 2002					62,897			62,897
Cash dividends on common stock					(45,000)			(45,000)
Repurchase of common stock	(87)			(37,000)				(37,000)
Allocation of benefits - ESOP				(1,063)	682			(381)
Other comprehensive loss						(511)		(511)
Balance at December 31, 2002	301	-		126,937	194,998	(105)		321,830

Net income for 2003					45,624			45,624
Cash dividends on common stock					(16,800)			(16,800)
Allocation of benefits - ESOP				(382)				(382)
Capital contribution from NU parent				30,000				30,000
Other comprehensive loss						(12)		(12)
Balance at December 31, 2003	301	-		156,555	223,822	(117)		380,260

Net income for 2004					46,641			46,641
Cash dividends on common stock					(27,186)			(27,186)
Allocation of benefits - ESOP				(220)				(220)
Tax deduction for stock options exercised and Employee Stock Purchase
Plan disqualifying dispositions				197				197
Other comprehensive income						7		7
Balance at December 31, 2004	301	$ -		$ 156,532	$ 243,277	$ (110)		$ 399,699

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

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


For the Years Ended December 31,	2004	2003	2002
	(Thousands of Dollars)

Operating activities:
Net income	$ 46,641	$ 45,624	$ 62,897
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	2,742	1,379	1,840
Depreciation	45,662	43,322	40,941
Deferred income taxes and investment tax credits, net	(24,160)	(6,670)	(79,866)
Amortization of regulatory assets, net	95,436	37,861	196,246
Amortization of rate reduction bonds	43,764	40,040	42,714
Amortization of recoverable energy costs	-	23,388	9,859
Regulatory overrecoveries/(refunds)	2,219	11,276	(34,315)
Other sources of cash	19,180	18,258	23,708
Other uses of cash	(12,206)	(56,765)	(19,858)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(33,867)	(9,136)	1,149
Fuel, materials and supplies	(5,411)	2,114	(7,135)
Other current assets	(6,248)	(6,445)	7,341
Accounts payable	28,058	3,723	7,583
Accrued taxes	(1,914)	(56,241)	55,874
Other current liabilities	(7,511)	(9,756)	14,253
Net cash flows provided by operating activities	192,385	81,972	323,231

Investing Activities:
Investments in plant	(143,647)	(105,354)	(107,008)
Buyout/buydown of IPP contracts	-	(20,437)	(5,152)
CVEC acquisition special deposit	-	(30,104)	-
Other investment activities	2,793	15,066	(8,269)
Net cash flows used in investing activities	(140,854)	(140,829)	(120,429)

Financing Activities:
Repurchase of common stock	-	-	(37,000)
Issuance of long-term debt	50,000	-	-
Issuance of rate reduction bonds	-	-	50,000
Retirement of rate reduction bonds	(43,453)	(38,619)	(46,540)
Increase/(decrease) in short-term debt	-	10,000	(60,500)
NU Money Pool (lending)/borrowing	(28,500)	71,900	(46,000)
Capital contribution from Northeast Utilities	-	30,000	-
Cash dividends on common stock	(27,186)	(16,800)	(45,000)
Other financing activities	(274)	(206)	(13,922)
Net cash flows (used in)/provided by financing activities	(49,413)	56,275	(198,962)
Net increase/(decrease) in cash	2,118	(2,582)	3,840
Cash - beginning of period	2,737	5,319	1,479
Cash - end of period	$ 4,855	$ 2,737	$ 5,319

Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized	$ 43,550	$ 45,639	$ 47,506
Income taxes	$ 49,452	$ 97,165	$ 56,458

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

Notes To Consolidated Financial Statements

1. Summary of Significant Accounting Policies

About Public Service Company of New Hampshire

Public Service Company of New Hampshire (PSNH or the company) is a wholly owned subsidiary of Northeast Utilities (NU). PSNH 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 PSNH, is subject to the provisions of the 1935 Act. Arrangements among PSNH, 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. PSNH is subject to further regulation for rates, accounting and other matters by the FERC and the New Hampshire Public Utilities Commission (NHPUC). PSNH, The Connecticut Light and Power Company (CL&P), and Western Massachu setts Electric Company (WMECO), furnish franchised retail electric service in New Hampshire, Connecticut and Massachusetts, respectively. PSNH’s results include the operations of its distribution and generation and transmission segments.

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

Presentation

The consolidated financial statements of PSNH 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 14, "Reclassification of Previously Issued Financial Statements," for the effects of the reclassifications.

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. NU 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 PSNH's accounting treatment at December 31, 2003 and reduced the projected benefit obligation by $1 million and $4.4 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 PSNH investments meeting the definition of a variable interest entity (VIE). FIN 46R was effective for PSNH for the first quarter of 2004 and did not have an impact on PSNH's consolidated financial statements.

Guarantees

At December 31, 2004, NU had outstanding guarantees on behalf of PSNH in the amount of $5.4 million. PSNH had no guarantees outstanding to unaffiliated entities.

Revenues

PSNH's retail revenues are based on rates approved by the NHPUC. 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 NHPUC.

PSNH 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.

Unbilled Revenues: Unbilled revenues represent an estimate of electricity or gas 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.

PSNH 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 $3.3 million.

Transmission Revenues: Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of PSNH’s wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and PSNH’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 PSNH’s wholesale transmission revenue requirements, net of revenues received from other sources, including those revenues received under RNS rates. PSNH’s LNS tariff is also reset on June 1st of each year to coincide with the change in RNS rates. Addit ionally, PSNH’s LNS tariff provides for a true-up to actual costs which ensures that PSNH recovers its wholesale transmission revenue requirements, including an allowed ROE.

A significant portion of PSNH's transmission business revenue is from charges to PSNH's distribution business. The distribution business recovers these charges through rates charged to its retail customers. The June 1, 2005 PSNH retail rate increase includes revenues to recover expected transmission costs. PSNH does not have a transmission cost tracking mechanism.

Derivative Accounting

Certain PSNH 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 Tax 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 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. PSNH 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 PSNH’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 purposes 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 interchangepower 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, and changes in fair value of these contracts are recorded primarily in expenses.

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

Regulatory Accounting

The accounting policies of PSNH 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, distribution and generation businesses of PSNH continue to be cost-of-service rate regulated. New Hampshire's electric utility industry restructuring laws have been modified to delay the sale of PSNH’s fossil and hydroelectric generation assets until at least April of 2006. There has been no regulatory action to the contrary and management currently has no plans to divest of these generation assets. As the NHPUC has allowed and is expected to continue to allow rate recovery of a return on and recovery of these assets, as well as all operating expenses, PSNH meets the criteria for the application of SFAS No. 71. Stranded costs related to generation assets, to the extent not currently recovered in rates, are deferred as Part 3 stranded costs under the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement). Part 3 stranded costs are non-securitized regul atory assets that must be recovered by a recovery end date determined in accordance with the Restructuring Settlement or be written off.

Management believes the application of SFAS No. 71 to the portions of the aforementioned businesses continues to be appropriate. Management also believes it is probable that PSNH 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 PSNH's regulatory assets are as follows:

	At December 31,
(Millions of Dollars)	2004	2003
Recoverable nuclear costs	$ 29.7	$ 33.3
Securitized assets	421.6	465.4
Income taxes, net	37.5	44.2
Unrecovered contractual obligations	64.4	69.9
Recoverable energy costs	194.9	218.3
Other	152.0	138.3
Totals	$900.1	$969.4

Additionally, PSNH had $0.1 million of regulatory costs at December 31, 2004 and 2003, 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 NHPUC. Management believes these costs are recoverable in future rates.

Recoverable Nuclear Costs: In March 2001, PSNH recorded a regulatory asset in conjunction with the sale of Millstone 3. This asset had an unamortized balance of $29.7 million and $33.3 million at December 31, 2004 and 2003, respectively, which is the balance in recoverable nuclear costs.

Securitized Assets: In April 2001, PSNH issued rate reduction bonds in the amount of $525 million. PSNH used the majority of the proceeds from that issuance to buydown its power contract with North Atlantic Energy Corporation (NAEC). The remaining PSNH securitized asset balance is $392.2 million and $427.5 million at December 31, 2004 and 2003, respectively.

In January 2002, PSNH issued an additional $50 million in rate reduction bonds and used the proceeds from that issuance to repay short-term debt that was incurred to buyout a purchased-power contract in December 2001. The remaining PSNH securitized asset balance for the January 2002 issuance is $29.4 million and $37.9 million at December 31, 2004 and 2003, respectively.

Securitized assets are being recovered over the amortization period of their associated rate reduction bonds. All outstanding rate reduction bonds of PSNH are scheduled to fully amortize by May 1, 2013.

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 NHPUC and SFAS No. 109. Differences in income taxes between SFAS No. 109 and the rate-making treatment of the NHPUC are recorded as regulatory assets. For further information regarding income taxes, see Note 1H, "Summary of Significant Accounting Policies - Income Taxes," and Note 11, "Income Tax Expense," to the consolidated financial statements.

Unrecovered Contractual Obligations: PSNH, under the terms of contracts with Connecticut Yankee Atomic Power Company (CYAPC), Yankee Atomic Power Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) collectively 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. Amounts for PSNH are being recovered along with other stranded costs. See Note 5D, "Deferred Contractual Obligations," to the consolidated financial statements for additional information.

Recoverable Energy Costs: In conjunction with the implementation of restructuring under the Restructuring Settlement on May 1, 2001, PSNH's fuel and purchased-power adjustment clause (FPPAC) was discontinued. At December 31, 2004 and 2003, PSNH had $144.8 million and $162.2 million, respectively, of recoverable energy costs deferred under the FPPAC. Under the Restructuring Settlement, the FPPAC deferrals are recovered as a Part 3 stranded cost through a stranded cost recovery charge (SCRC). Also included in PSNH's recoverable energy costs are deferred costs associated with certain contractual purchases from IPPs. These costs are also treated as Part 3 stranded costs and amounted to $50.1 million and $56.1 million at December 31, 2004 and 2003, respectively.

All recoverable energy costs are currently recovered in rates from the customers of PSNH. PSNH's recoverable energy costs are Part 3 stranded costs which are nonsecuritized regulatory assets which must be recovered by a recovery end date determined in accordance with the Restructuring Settlement or be written off. Based on current projections, PSNH expects to fully recover all of its Part 3 costs by the recovery end date.

Regulatory Liabilities: PSNH had $323.7 million and $272.6 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	$ 87.6	$ 88.0
Cumulative deferrals - SCRC	208.6	160.4
Other regulatory liabilities	27.5	24.2
Totals	$323.7	$272.6

Under SFAS No. 71, PSNH 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 SCRC allows PSNH to recover its stranded costs.

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 applicable regulatory commissions 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	$ 2.6	$ 2.3
Deferred tax assets - current:
Provision for uncollectible accounts	0.7	0.6
Net deferred tax liabilities - current	1.9	1.7
Deferred tax liabilities - long-term:
Accelerated depreciation and other plant-related differences	145.4	117.6
Securitized costs	154.1	173.3
Income tax gross-up	15.0	17.8
Deferred fuel and small power producer costs	81.8	91.9
Other	68.2	66.4
Total deferred tax liabilities - long-term	464.5	467.0
Deferred tax assets - long-term:
Regulatory deferrals	124.1	96.7
Employee benefits	25.8	21.0
Income tax gross-up	0.9	1.0
Other	1.7	11.1
Total deferred tax assets - long-term	152.5	129.8
Net deferred tax liabilities - long-term	312.0	337.2
Net deferred tax liabilities	$313.9	$338.9

NU and its subsidiaries, including PSNH, file a consolidated federal income tax return. NU and its subsidiaries, including PSNH, 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.

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 14 years to 75 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 2.9 percent in 2004 and 3 percent in 2003 and 2002.

Jointly Owned Electric Utility Plant

At December 31, 2004, PSNH owns common stock in three regional nuclear companies (Yankee Companies). PSNH’s ownership interests in the Yankee Companies at December 31, 2004, which are accounted for on the equity method are 5 percent of CYAPC, 7 percent of YAEC and 5 percent of MYAPC. In 2003, PSNH sold its collective 4.3 percent ownership interest in Vermont Yankee Nuclear Power Corporation (VYNPC). PSNH’s total equity investment in the Yankee Companies at December 31, 2004 and 2003 is $4 million and $4.6 million, respectively. Each of the remaining Yankee Companies owns a single nuclear generating plant which is being decommissioned. Earnings related to these equity investments are included in other income/(loss) on the accompanying consolidated statements of income. For further information, see Note 1O, "Other Income/(Loss)," to the consolidated financial s tatements. Each of the remaining Yankee Companies owns a single nuclear generating plant which is being decommissioned.

PSNH owns 5 percent of the common stock of CYAPC with a carrying value of $2.2 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 PSNH's investment. For further information regarding the Bechtel litigation, see Note 5D, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.

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	$ 0.3	$0.6	$1.0
Equity funds	(0.1)	0.6	0.6
Totals	$ 0.2	$1.2	$1.6
Average AFUDC rates	2.5%	3.9%	4.7%

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.

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 PSNH. 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 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-licensin g issues. These obligations are AROs that have not been incurred or are not material in nature.

If adopted in its current form, there may be an impact to PSNH for AROs that PSNH 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 PSNH. The interpretation is scheduled to be issued in the first quarter of 2005 and would be effective for PSNH no later than December 31, 2005.

A portion of PSNH’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 $87.6 million and $88 million, respectively.

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.

Special Deposits

Special deposits at December 31, 2003 totaled $30.1 million in escrow that PSNH funded to acquire Connecticut Valley Electric Company (CVEC) on January 1, 2004.

Other Income/(Loss)

The pre-tax components of PSNH’s other income/(loss) items are as follows:

For the Years Ended December 31,
(Millions of Dollars)	2004	2003	2002
Other Income:
Investment income	$ 0.4	$ 0.6	$ 1.7
AFUDC - equity funds	-	0.6	0.6
Conservation load management incentive	1.8	-	-
Gain on sale of property	1.3	0.3	1.3
Other	1.1	0.9	1.0
Total Other Income	4.6	2.4	4.6
Other Loss:
Charitable donations	(0.4)	(0.4)	(0.4)
Costs not recoverable from regulated customers	(0.9)	(2.3)	(0.4)
Other	(4.3)	(4.7)	(5.5)
Total Other Loss	(5.6)	(7.4)	(6.3)
Totals	$(1.0)	$(5.0)	$(1.7)

Investment income includes equity in earnings of regional nuclear generating and transmission companies of $0.2 million in 2004, $0.4 million in 2003 and $1.3 million in 2002. Equity in earnings relates to PSNH's investment in the Yankee Companies.

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

Provision for Uncollectible Accounts

PSNH 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 PSNH is subject to periodic approval by either the SEC under the 1935 Act or by the NHPUC. On June 30, 2004, the SEC granted authorization allowing PSNH to incur total short-term borrowings up to a maximum $100 million through June 30, 2007. The SEC also granted authorization for borrowing through the NU Money Pool (Pool).

PSNH is authorized by the NHPUC to incur short-term debt borrowings of $100 million.

Credit Agreement: On November 8, 2004, PSNH entered into a 5-year unsecured revolving credit facility for $400 million. This facility replaces a $300 million credit facility that expired on November 8, 2004. PSNH may draw up to $100 million. Unless extended, the credit facility will expire on November 6, 2009. At December 31, 2004 and 2003, there were $10 million in borrowings under this credit facility.

Under the aforementioned credit agreement, PSNH 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 PSNH’s notes payable to banks outstanding on December 31, 2004 and 2003 was 5.25 percent and 2 percent, respectively.

Under the credit agreement, PSNH must comply with certain financial and non-financial covenants as are customarily included in such agreements, including but not limited to, consolidated debt ratios and interest coverage ratios. The most restrictive financial covenant is the interest coverage ratio. PSNH 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: PSNH 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, PSNH had borrowings of $20.4 and $48.9 million, respectively. The in terest 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 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 consolida ted 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.

PSNH has energy contracts that are subject to unplanned netting and do not meet the definition of capacity contracts. These non-trading derivative contracts were recorded at fair value at December 31, 2003 as derivative assets ofapproximately $1.4 million and derivative liabilities with a fair value of approximately $1.4 million with offsetting regulatory assets and regulatory liabilities, respectively. The contracts were not outstanding at December 31, 2004.

To mitigate the risk associated with certain supply contracts, PSNH purchased Financial Transmission Rights (FTR). FTRs are derivatives that cannot qualify for the normal purchases and sales exception. The fair value of these FTR non-trading derivatives at December 31, 2003 was an asset of $0.1 million. PSNH had no non-trading derivatives at December 31, 2004 that were required to be recorded at fair value.

4. Pension Benefits and Postretirement Benefits Other Than Pensions

Pension Benefits: PSNH 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 expense was $12.4 million in 2004, $6.8 million in 2003 and $0.6 million in 2002. PSNH uses a December 31 measurement date for the Pension Plan. Pension expense attributable to earnings is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2004	2003	2002
Pension expense	$12.4	$ 6.8	$ 0.6
Net pension expense capitalized as utility plant	(3.4)	(2.0)	(0.2)
Total pension expense included in earnings	$ 9.0	$4.8	$ 0.4

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

Market-Related Value of Pension Plan Assets: PSNH 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 (PBOP): PSNH 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 PSNH 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. PSNH uses a December 31 measurement date for the PBOP Plan.

PSNH 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, PSNH’s actuaries believe that PSNH will qualify for this federal subsidy because the actuarial value of PSNH’s PBOP Plan is estimated to be 60 percent greater than that of the standard Medicare benefit. PSNH will directly benefit from the federal subsidy for retirees who retired before 1993. For other retirees, management does not believe that PSNH will benefit from the subsidy because PSNH’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 $4.4 million decrease in the PBOP benefit obligation at December 31, 2003 to $5.4 million at January 1, 2004. The total $5.4 million decrease consists of $4.4 million as a direct result of the subsidy for certain non-capped retirees and $1 million related to changes in participation assumptions for capped retirees and future retirees as a result of the subsidy. The total $5.4 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 $0.7 million, including amortization of the actuarial gain of $0.4 million and a reduction in interest and service costs based on a lower PBOP benefit obligation of $0.3 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	$(289.0)	$(260.9)	$ (66.8)	$ (63.7)
Service cost	(7.4)	(6.4)	(1.3)	(1.1)
Interest cost	(17.9)	(17.3)	(4.3)	(4.5)
Medicare prescription drug benefit impact	N/A	N/A	-	4.4
Transfers	(0.5)	-	(0.1)	-
Actuarial loss	(23.2)	(17.3)	(12.8)	(8.5)
Benefits paid	14.1	12.9	5.6	6.6
Benefit obligation at end of year	$(323.9)	$(289.0)	$ (79.7)	$ (66.8)
Change in plan assets
Fair value of plan assets at beginning of year	$ 192.0	$ 163.5	$ 29.7	$ 24.4
Actual return on plan assets	23.2	41.3	2.9	5.7
Employer contribution	-	-	7.5	6.2
Transfers	0.5	-	0.1	-
Benefits paid	(14.1)	(12.9)	(5.6)	(6.6)
Fair value of plan assets at end of year	$ 201.6	$ 191.9	$ 34.6	$ 29.7
Funded status at December 31	$(122.3)	$ (97.1)	$ (45.1)	$ (37.1)
Unrecognized transition obligation	1.6	2.0	19.8	22.4
Unrecognized prior service cost	11.4	13.0	-	-
Unrecognized net loss	52.1	37.3	25.1	14.7
Accrued benefit cost	$ (57.2)	$ (44.8)	$ (0.2)	$ -

The accumulated benefit obligation (ABO) for the Plan was $270.7 million and $243.6 million at December 31, 2004 and 2003, respectively. Total Pension Plan assets on an NU consolidated basis were approximately $225 million and approximately $240 million more than the ABO 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	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	$ 7.4	$ 6.4	$ 5.8	$1.2	$ 1.1	$ 1.1
Interest cost	17.9	17.3	16.8	4.3	4.5	4.6
Expected return on plan assets	(17.1)	(18.2)	(20.3)	(2.1)	(2.6)	(2.9)
Amortization of unrecognized net transition obligation	0.3	0.3	0.3	2.5	2.5	2.8
Amortization of prior service cost	1.5	1.5	1.4	-	-	-
Amortization of actuarial loss/(gain)	2.4	(0.5)	(3.4)	-	-	-
Other amortization, net	-	-	-	1.6	0.7	(0.3)
Total - net periodic expense	$12.4	$ 6.8	$ 0.6	$7.5	$ 6.2	$ 5.3

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

6.85%

7.25%

Life assets and non-taxable

health assets

N/A

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%

Year that the rate reaches the
ultimate trend rate

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

$0.1

$(0.1)

Effect on postretirement

benefit obligation

$2.6

$(2.3)

PSNH'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. PSNH'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, PSNH also evaluated input from actuaries and consultants as well as long-term inflation assumptions and PSNH'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 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. 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	$ 13.8	$ 6.1	$ -
2006	14.3	6.2	0.5
2007	15.0	6.4	0.5
2008	15.8	6.4	0.5
2009	16.8	6.5	0.5
2010-2014	101.5	32.3	2.4

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

Contributions: PSNH does not expect to make any contributions to the Pension Plan in 2005 and expects to make $9.1 million in contributions to the PBOP Plan in 2005.

Currently, PSNH’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. Commitments and Contingencies

Regulatory Developments and Rate Matters

SCRC Reconciliation Filings: The SCRC allows PSNH to recover its stranded costs. On an annual basis, PSNH files with the NHPUC a SCRC reconciliation filing for the preceding calendar year. This filing includes the reconciliation of stranded cost revenues billed with stranded costs, and transition energy service and default energy service (TS/DS) revenues billed with TS/DS costs. The NHPUC reviews the filing, including a prudence review of PSNH's generation operations. The cumulative deferral of SCRC revenues in excess of costs was $208.6 million at December 31, 2004. This cumulative deferral will decrease the amount of non-securitized stranded costs that will have to be recovered from PSNH's customers in the future from $411.3 million to $202.7 million.

The 2003 SCRC reconciliation filing was filed with the NHPUC on April 30, 2004, and a stipulation and settlement agreement between PSNH, the Office of Consumer Advocate and NHPUC staff was filed with the NHPUC on October 4, 2004. Under the terms of the settlement agreement, no costs related to the recovery of stranded costs or the cost of providing transition energy service were disallowed and the NHPUC staff agreed to accept the 2003 SCRC filing without change. On October 29, 2004, the NHPUC issued an order accepting the settlement agreement as filed.

revenue balances in the recovery of SCRC and TS/DS costs. Management believes that the unbilled revenue balance related to SCRC and TS/DS is probable of being recovered from PSNH's customers.

Environmental Matters

General: PSNH 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, PSNH 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, ranging from no action to 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, PSNH had $7.3 million and $9.8 million, respectively, recorded as environmental reserves. A reconciliation of the total reserve amount 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	$9.8	$10.8
Additions and adjustments	3.1	0.8
Payments	(5.6)	(1.8)
Balance at end of year	$7.3	$ 9.8

PSNH currently has 17 sites included in the environmental reserve. Of those 17 sites, ten sites are in the remediation or long-term monitoring phase, two sites have had site assessments completed and the remaining five sites are in the preliminary stages of site assessment.

For two 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, $1.6 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 million to $5.3 million as management utilizes the probabilistic model approach to make its estimate of the liability for environmental costs. For the 15 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 two sites for which there are unasserted claims; however, any related remediation costs are not probable or estimable at this time. PSNH'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 PSNH's environmental liability. MGPs are sites that manufactured gas from coal and produced certain byproducts that may pose risk to human health and the environment. At December 31, 2004 and 2003, $6.3 million and $9.1 million, respectively, represent amounts for the site assessment and remediation of MGPs. At December 31, 2004 and 2003, the two largest MGP sites comprise approximately 86 percent and 87 percent, respectively, of the total MGP environmental liability.

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. PSNH 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 PSNH is not managing the site assessment and remediation, the liability accrued represents PSNH'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 as necessary.

Rate Recovery: PSNH has a rate recovery mechanism for environmental costs.

Long-Term Contractual Arrangements

VYNPC: Previously, under the terms of its agreement, PSNH paid its ownership (or entitlement) shares 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 Corporation (Entergy) for approximately $180 million. Under the terms of the sale, PSNH will continue to buy approximately 4 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 $6.7 million in 2004, $7.5 million in 2003, and $6.9 million in 2002.

Electricity Procurement Obligations: PSNH has entered into various arrangements for the purchase of electricity. The total cost of purchases under these arrangements amounted to $121.1 million in 2004, $122.8 million in 2003, and $121.2 million in 2002. These amounts are for independent power producer (IPPs) contracts and do not include PSNH’s short-term power supply management.

Hydro-Quebec: Along with other New England utilities, PSNH has entered into an agreement to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. PSNH 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 $7.4 million in 2004, $7.9 million in 2003 and $9 million in 2002.

Northern Wood Power Project: In October 2004, PSNH received the approvals necessary to begin construction related to the conversion of one of three 50 megawatt units at the coal-fired Schiller Station to burn wood. Construction of the $75 million Northern Wood Power Project has begun and is expected to be completed by late 2006. Certain other estimated construction expenditures totaling $8.6 million are not included in the contract signed to perform the Schiller Station conversion and are not included in the table of estimated future annual costs below.

Yankee Companies FERC-Approved Billings: PSNH 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 PSNH. PSNH in turn passes these costs on to its 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 PSNH’s significant long-term contractual arrangements are as follows:

(Millions of

Dollars)

2005

2006

2007

2008

2009

Thereafter

VYNPC

$ 6.8

$ 7.1

$ 6.9

$ 7.0

$ 7.6

$ 16.6

Electricity

Procurement

Contracts

123.7

125.2

52.6

27.6

27.8

211.2

Hydro-Quebec

7.7

7.6

7.1

6.3

6.0

66.0

Northern Wood

Power Project

39.3

7.5

Yankee

Companies

FERC-

Approved

Billings

12.6

10.2

9.4

8.1

7.2

7.0

Totals

$190.1

$157.6

$76.0

$49.0

$48.6

$300.8

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. PSNH's share of CYAPC's increase in decommissioning and plant closure costs is approximately $20 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 beginning on Janua ry 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, PSNH's estimated remaining decommissioning and plant closure obligation for CYAPC is $31.5 million at December 31, 2004.

On June 10, 2004, the Connecticut Department of Public Utility Control (DPUC) and Office of Consumer Counsel of the state of Connecticut (OCC) filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including PSNH, 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.

Therefore, the DPUC recommends a total disallowance of between $225 million to $234 million. Hearings are expected to begin on June 1, 2005. PSNH’s share of the DPUC’s recommended disallowance is $11 million to $12 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.

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 PSNH. 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. PSNH 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 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. The Yankee Companies' individual damage claims attributed to the government's breach t otaling $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 PSNH.

6. Fair Value of Financial Instruments

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

Special Deposits: The carrying amounts approximate fair value due to the short-term nature of these cash items.

Long-Term Debt and Rate Reduction Bonds: The fair value of PSNH’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 PSNH’s financial instruments and the estimated fair values are as follows:

	At December 31, 2004
(Millions of Dollars)	Carrying Amount	Fair Value
Long-term debt -
First mortgage bonds	$ 50.0	$ 51.0
Other long-term debt	407.3	427.5
Rate reduction bonds	428.8	464.8

	At December 31, 2003
(Millions of Dollars)	Carrying Amount	Fair Value
Long-term debt -
Other long-term debt	$407.3	$425.6
Rate reduction bonds	472.2	517.3

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

7. Leases

PSNH 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 $0.4 million in 2004, $0.5 million in 2003, and $0.4 million in 2002. Interest included in capital lease rental payments was $0.2 million in 2004, $0.3 million in 2003 and 2002. Operating lease rental payments charged to expense were $4 million in 2004, $3.3 million in 2003, and $3.8 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	$0.5	$ 6.6
2006	0.4	6.1
2007	0.2	5.1
2008	0.2	3.9
2009	-	1.8
Thereafter	-	3.8
Future minimum lease payments	1.3	$27.3
Less amount representing interest	0.6
Present value of future minimum lease payments	$0.7

8. Dividend Restrictions

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

The unsecured revolving credit agreement also limits dividend payments subject to the requirements that the PSNH'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 $89 million.

9. 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

$ 0.2

Minimum supplemental

executive retirement

pension liability

adjustments

(0.2)

(0.1)

(0.3)

Accumulated other

comprehensive loss

$(0.1)

$ -

$(0.1)

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

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)

$(0.1)

$0.3

Minimum supplemental

executive retirement pension

liability adjustments

Accumulated other

comprehensive (loss)/income

$(0.1)

$0.3

10. Long-Term Debt

Details of long-term debt outstanding are as follows:

At December 31,	2004	2003
	(Millions of Dollars)
First Mortgage Bonds:
5.25% Series L, due 2014	$ 50.0	$ -
Pollution Control Revenue Bonds:
6.00% Tax-Exempt, Series D, due2021	75.0	75.0
6.00% Tax-Exempt , Series E, due 2021	44.8	44.8
Adjustable Rate, Series A, due 2021	89.3	89.3
Adjustable Rate, Series B, due 2021	89.3	89.3
5.45% Tax-Exempt, Series C, due 2021	108.9	108.9
Total Pollution Control Revenue Bonds	$407.3	$407.3
Less amounts due within a year	-	-
Unamortized premiums and discounts, net	(0.1)	-
Long-term debt	$457.2	$407.3

There are no cash sinking fund requirements or debt maturities for the years 2005 through 2009. There are annual renewal and replacement fund requirements equal to 2.25 percent of the average of net depreciable utility property owned by PSNH in 1992, plus cumulative gross property additions thereafter. PSNH expects to meet these future fund requirements by certifying property additions. Any deficiency would need to be satisfied by the deposit of cash or bonds.

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

PSNH entered into financing arrangements with the Business Finance Authority (BFA) of the state of New Hampshire, pursuant to which, the BFA issued five series of Pollution Control Revenue Bonds (PCRBs) as described above and loaned the proceeds to PSNH. PSNH's obligation to repay each series of PCRBs is secured by bond insurance and first mortgage bonds. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. For financial reporting purposes, these first mortgage bonds would not be considered outstanding unless PSNH failed to meet its obligations under the PCRBs.

The average effective interest rate on the variable-rate pollution control notes was 1.25 percent in 2004 and 1 percent in 2003.

11. 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	$37.2	$27.9	$101.1
State	-	8.5	19.0
Total current	37.2	36.4	120.1
Deferred income taxes, net:
Federal	(17.7)	(3.8)	(65.0)
State	(6.0)	(2.3)	(5.5)
Total deferred	(23.7)	(6.1)	(70.5)
Investment tax credits, net	(0.5)	(0.5)	(9.3)
Total income tax expense	$13.0	$29.8	$ 40.3

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	$20.9	$26.3	$36.1
Tax effect of differences:
Depreciation	1.3	1.1	1.9
Amortization of regulatory assets	1.8	1.8	1.2
Investment tax credit amortization	(0.5)	(0.5)	(9.3)
State income taxes, net of federal benefit	(3.9)	4.1	8.8
Parent company loss	(1.7)	-	-
Other, net	(4.9)	(3.0)	1.6
Total income tax expense	$13.0	$29.8	$40.3

12. Nuclear Generation Asset Divestitures

Seabrook: On November 1, 2002, CL&P and NAEC consummated the sale of their 40.04 percent combined ownership interest in Seabrook to a subsidiary of FPL Group, Inc. (FPL). CL&P, NAEC and certain other of the joint owners collectively sold 88.2 percent of Seabrook to FPL. NU received approximately $367 million of total cash proceeds from the sale of Seabrook and another approximately $17 million from Baycorp Holdings, Ltd., as a result of the sale of its interest in Seabrook. A portion of this cash was used to repay all $90 million of NAEC's outstanding debt and other short-term debt, to return a portion of NAEC's equity to NU and was used to pay approximately $93 million in taxes. The remaining proceeds received by NAEC were refunded to PSNH through the Seabrook Power Contracts. As part of the sale, FPL assumed responsibility for decommissioning Seabrook. NAEC and CL& ;P recorded a gain on the sale in the amount of approximately $187 million, which was primarily used to offset stranded costs.

VYNPC: On July 31, 2002, VYNPC consummated the sale of its nuclear generating plant to a subsidiary of Entergy for approximately $180 million. As part of the sale, Entergy assumed responsibility for decommissioning VYNPC's nuclear generating unit. In 2003, PSNH sold its collective 4.3 percent ownership interest in VYNPC. PSNH will continue to buy approximately 4 percent of the plant's output through March 2012 at a range of fixed prices.

13. Segment Information

Segment information related to the distribution (including generation) and transmission businesses for PSNH 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	$ 938.0	$30.8	$ 968.8
Depreciation and amortization	(180.5)	(4.4)	(184.9)
Other operating expenses	(661.9)	(15.8)	(677.7)
Operating income	95.6	10.6	106.2
Interest expense, net of AFUDC	(43.6)	(1.9)	(45.5)
Interest income	0.4	-	0.4
Other (loss)/income, net	(2.0)	0.5	(1.5)
Income tax expense	(10.6)	(2.4)	(13.0)
Net income	$ 39.8	$ 6.8	$ 46.6
Total Assets (1)	$2,212.7	$ -	$2,212.7
Cash flows for total investments in plant	$ 115.4	$ 28.2	$ 143.6

For the Year Ended December 31, 2003
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$ 863.0	$25.2	$ 888.2
Depreciation and amortization	(118.3)	(3.0)	(121.3)
Other operating expenses	(631.0)	(10.3)	(641.3)
Operating income	113.7	11.9	125.6
Interest expense, net of AFUDC	(44.8)	(0.5)	(45.3)
Interest income	(0.4)	-	(0.4)
Other loss, net	(4.4)	(0.1)	(4.5)
Income tax expense	(25.8)	(4.0)	(29.8)
Net income	$ 38.3	$ 7.3	$ 45.6
Total Assets (1)	$2,171.2	$ -	$2,171.2
Cash flows for total investments in plant	$ 78.4	$27.0	$ 105.4

(1) Information for segmenting total assets between distribution and transmission is not available at December 31, 2004 or December 31, 2003. The distribution and transmission assets are disclosed in the distribution columns above.

For the Year Ended December 31, 2002
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$919.8	$27.4	$947.2
Depreciation and Amortization	(277.2)	(2.7)	(279.9)
Other operating expenses	(502.1)	(11.2)	(513.3)
Operating income	140.5	13.5	154.0
Interest expense, net of AFUDC	(48.8)	(0.3)	(49.1)
Interest income	0.2	-	0.2
Other loss, net	(1.9)	-	(1.9)
Income tax expense	(40.4)	0.1	(40.3)
Net income	$ 49.6	$13.3	$ 62.9
Cash flows for total investments in plant	$ 90.8	$16.2	$107.0

14. 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
Accumulated deferred income taxes	$338,930	$337,206
Accrued taxes	2,543	1,914
Fuel, materials and supplies at average cost	54,533	47,068
Prepayments and other	9,945	9,315
Other current liabilities	16,689	17,914
Other assets	60,324	67,789
Regulatory liabilities	272,081	272,579

Reclassifications to income statement amounts are as follows:

For Year Ended December 31, 2003
	Previously Reported	As Reclassified
Fuel, purchased and net interchange power	$400,518	$404,431
Other	142,550	138,637

For Year Ended December 31, 2002
	Previously Reported	As Reclassified
Fuel, purchased and net interchange power	$288,427	$289,713
Other	126,506	125,220

Consolidated Quarterly Financial Data (Unaudited)
(Thousands of Dollars)	Quarter Ended (a)
2004	March 31,	June 30,	September 30,	December 31,
Operating Revenues	$244,148	$226,448	$258,876	$239,277
Operating Income	$ 31,484	$ 20,234	$ 30,386	$ 24,055
Net Income	$ 11,760	$ 6,025	$ 18,239	$ 10,617
2003
Operating Revenues	$230,768	$203,364	$235,972	$218,082
Operating Income	$ 31,383	$ 29,668	$ 34,774	$ 29,791
Net Income	$ 10,827	$ 11,054	$ 12,613	$ 11,130

Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars)	2004	2003	2002	2001	2000
Operating Revenues (b)	$ 968,749	$ 888,186	$ 947,178	$ 964,415	$ 1,291,280
Net Income/(Loss)	46,641	45,624	62,897	81,776	(146,666)
Cash Dividends on Common Stock	27,186	16,800	45,000	27,000	50,000
Property, Plant and Equipment, net (c)	1,031,703	925,592	839,716	809,740	829,139
Total Assets (d)	2,212,699	2,171,181	2,155,447	2,094,514	2,082,296
Rate Reduction Bonds	428,769	472,222	510,841	507,381	-
Long-Term Debt (e)	457,190	407,285	407,285	407,285	407,285
Preferred Stock Not Subject to Mandatory Redemption	-	-	-	-	24,268
Obligations Under Seabrook Power Contracts and Other Capital Leases (e)	712	986	1,192	110,275	629,230

Consolidated Statistics (Unaudited)
	2004	2003	2002	2001	2000
Revenues: (Thousands)
Residential	$384,667	$351,622	$325,912	$323,642	$ 355,176
Commercial	361,603	318,081	297,196	297,632	306,386
Industrial	175,921	159,560	150,582	175,575	195,058
Other Utilities	19,712	38,622	152,131	144,350	394,080
Streetlighting and Railroads	5,297	4,801	4,820	5,227	5,925
Miscellaneous	21,549	15,500	16,537	17,989	34,655
Total	$968,749	$888,186	$947,178	$964,415	$1,291,280
Sales: (kWh - Millions)
Residential	3,015	2,944	2,765	2,592	2,474
Commercial	3,235	3,100	2,969	2,873	2,614
Industrial	1,716	1,684	1,646	1,926	2,026
Other Utilities	242	674	4,034	4,086	10,007
Streetlighting and Railroads	25	23	23	23	22
Total	8,233	8,425	11,437	11,500	17,143
Customers: (Average)
Residential	403,088	388,133	382,481	376,832	372,286
Commercial	66,572	63,324	61,775	59,538	58,279
Industrial	2,783	2,758	2,818	2,863	2,887
Other	572	554	540	517	485
Total	473,015	454,769	447,614	439,750	433,937
Average Annual Use Per Residential Customer (kWh)	7,484	7,584	7,208	6,868	6,644
Average Annual Bill Per Residential Customer	$954.96	$905.52	$849.10	$859.87	$954.08
Average Revenue Per kWh:
Residential	12.76¢	11.94¢	11.78¢	12.52¢	14.36¢
Commercial	11.18	10.26	10.01	10.36	11.72
Industrial	10.25	9.48	9.15	9.12	9.63

(a)

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

(b)

Operating revenue amounts for 2000 do not reflect the adoption of EITF Issue No. 03-11.

(c)

Amount includes construction work in progress.

(d)

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

(e)

Includes portions due within one year.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

Western Massachusetts Electric Inactive 10-K2004 FY Annual report

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