FORM 10-Q

For the quarterly period ended June 30, 2004

              For the transition period from __________ to __________

NEW ENGLAND POWER COMPANY

FORM 10-Q - For the Quarter Ended June 30, 2004

Per share data is not relevant because the Company’s common stock is wholly owned by National Grid USA.

NEW ENGLAND POWER COMPANY
Condensed Statements of Comprehensive Income
Periods Ended June 30
(In thousands of dollars)
(UNAUDITED)

                                           Three Months

Per share data is not relevant because the Company’s common stock is wholly owned by National Grid USA.

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

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

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

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

Basis of Presentation: New England Power Company (the Company), in the opinion of management, has included all adjustments (which include normal recurring adjustments) necessary for a fair statement of the results of its operations for the interim periods presented. The March 31, 2004 condensed balance sheet data included in this quarterly report on Form 10-Q was derived from audited financial statements included in the Company’s Annual Report on Form 10-K for the year ended March 31, 2004. As such, the March 31, 2004 balance sheet included in this Form 10-Q is considered unaudited as it does not include all the footnote disclosures contained in the Company’s Form 10-K. These financial statements and the notes thereto should be read in conjunction with the audited financial statements included in the Company’s Annual Report on Form 10-K for the year ended March 31, 2004.

Reclassifications: Certain amounts from prior years have been reclassified in the accompanying financial statements to conform to the current year presentation.

The company is a wholly owned subsidiary of National Grid USA and, indirectly National Grid Transco plc.

New Accounting Standards: On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The Act expands Medicare, primarily by adding a prescription drug benefit for Medicare-eligibles starting in 2006.  The Act provides employers currently sponsoring prescription drug programs for Medicare-eligibles with a range of options for coordinating with the new government-sponsored program to potentially reduce program cost. These options include supplementing the government program on a secondary payor basis or accepting a direct subsidy from the government to support a portion of the cost of the employer's program.  

Paragraph 40 of the Financial Accounting Standards Board's (FASB) Statement of Financial Accounting Standard (SFAS) No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions requires that presently enacted changes in laws impacting employer-sponsored retiree health care programs which take effect in future periods be considered in current-period measurements for benefits expected to be provided in those future periods. Therefore, under FAS 106 guidance, measures of plan liabilities and annual expense on or after the date of enactment should reflect the effects of this Act.

Pursuant to guidance from the FASB under FSP FAS 106-2, the retiree health obligations will reflect the estimated subsidy payments expected from the federal government for the participant groups anticipated to qualify for the subsidy.  Participant groups who are not expected to qualify, or have not yet been determined whether they will qualify, for the federal subsidy will not impact the retiree health obligations. If any portion of this group is subsequently determined to qualify for the subsidy, the retiree health care obligations will be adjusted at the time of that determination. The Company has chosen to apply the guidance prospectively, impacting retiree health costs effective July 1, 2004.

Because electricity rates have historically been based on a utility's costs, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. The Company applies the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (FAS 71), which requires regulated entities, in appropriate circumstances, to establish regulatory assets or liabilities, and thereby defer the income statement impact of certain charges or revenues because they are expected to be collected or refunded through future customer billings.

The Company has received authorization from the Federal Energy Regulatory Commission (FERC) to recover through contract termination charges (CTCs) substantially all of the costs associated with its former generating business not recovered through the divestiture of the generation assets. Additionally, FERC enables transmission companies to recover their specific costs of providing transmission service. Therefore, substantially all of the Company’s business, including the recovery of its stranded costs, remains under cost-based rate regulation.

Under settlement agreements, the Company is permitted to recover costs associated with its former generating investments (nuclear and nonnuclear) and related contractual commitments that were not recovered through the sale of those investments (stranded costs). Stranded costs are recovered from the Company’s wholesale customers with whom it has settlement agreements through a CTC which the affiliated former wholesale customers recover through delivery charges to distribution customers. The Company earns a return on equity (ROE) of approximately 9.7 percent on stranded cost recovery. Most stranded costs will be fully recovered through CTCs by the end of 2010. The Company’s stranded cost obligation related to the above-market cost of purchased power contracts and nuclear decommissioning costs are recovered through the CTC as such costs are actually incurred. The Company, under certain settlement agreements, earns incentives based on successful mitigation of its stranded costs and these incentives supplement the Company’s ROE.

As a result of applying FAS 71, the Company has recorded a regulatory asset for the costs that are recoverable from customers through CTCs. At June 30, 2004 and March 31, 2004 this amounted to approximately $1.0 billion and $1.1 billion, respectively, including $0.6 billion and $0.7 billion, respectively, related to the above-market costs of purchased power contracts, $0.2 billion and $0.3 billion, respectively, related to accrued nuclear plant costs, and $0.2 billion and $0.2 billion, respectively, related to other net regulatory assets.

In conjunction with the divestiture of its generating business, the Company transferred its entitlement to power procured under several long-term contracts (the Contracts) to US Gen New England Inc. (USGen), Constellation Power Source, Inc. and Transcanada Power Marketing Ltd. (the Buyers). The Buyers agreed to fulfill the Company’s performance and payment obligations under the Contracts. At the same time the Company agreed to pay the Buyers a fixed amount monthly for the above-market cost of the Contracts. Annually these fixed payments by the Company average approximately $106 million through December 2007 decreasing to approximately $12 million for 2008 then decreasing to approximately $3 million annually from 2009 to 2014. The net present value of these fixed monthly payments is recorded as a liability with an equal balance recorded in regulatory assets representing the future collection of the liability from ratepayers. At June 30, 2004 and March 31, 2004, the net present value of the liability for the fixed monthly payment is approximately $369 million and $398 million, respectively.

On July 8, 2003, PG&E National Energy Group (USGen’s parent company) and USGen separately filed for bankruptcy protection. In the event that the bankruptcy court relieved USGen from meeting its obligations under the purchased power transfer agreement (the Transfer Agreement), the Company would resume the performance and payment obligations under the Contracts. At that point the Company would remove the liability and a corresponding regulatory asset for the above market cost of the Contracts from its balance sheet. At June 30, 2004, the Company’s capitalized cost of the above market portion of the USGen Contracts is approximately $307 million. To date USGen continues to perform under the Transfer Agreement. Resumption of the performance payment obligations in the case of a default by USGen would not materially affect the results of operations, as the Company would continue to pass the above-market cost of the Contracts to customers through a CTC.

Separate from the Transfer Agreement, USGen asked the bankruptcy court to relieve it of obligations under Hydro Quebec transmission line agreements (HQ Contracts) under which it was obligated to reimburse the Company for monthly costs of approximately $1 million. USGen and the Company entered into a stipulation under which USGen continued to reimburse the Company through April 1, 2004. As of April 2, 2004, the Company resumed performance and payment under the HQ Contracts. The Company has a claim against USGen in bankruptcy for its damages. The Company’s resumption of performance and payment obligations will not affect the results of operations, as the Company will be able to recover any remaining costs through CTC’s from its customers.

Decommissioning Nuclear Units: The Company has minority interests in three nuclear generating companies: Yankee Atomic Electric Company, Connecticut Yankee Atomic Power Company, and Maine Yankee Atomic Power Company (together, the Yankees). These ownership interests are accounted for on the equity method. The Yankees own nuclear generating units that have been permanently retired and are conducting decommissioning operations. These three units are as follows:

With respect to each of these units, NEP has recorded a liability and a regulatory asset reflecting the estimated future decommissioning billings from the companies. In a 1993 decision, the FERC allowed Yankee Atomic to recover its undepreciated investment in the plant, including a return on that investment, as well as unfunded nuclear decommissioning costs and other costs.

Maine Yankee and Connecticut Yankee recover their prudently incurred costs, including a return, in accordance with settlement agreements approved by the FERC in May 1999 and July 2000, respectively. The Company’s share of the decommissioning costs is accounted for in "Purchased electricity" on the income statement.

Future estimated billings from the Yankees are based upon decommissioning cost estimates. These estimates include the projected costs of decontaminating the units as required by the Nuclear Regulatory Commission (NRC), dismantling the units, spent fuel storage, security, and liability and property insurance, as well as other costs. The decommissioning costs that are actually incurred by the Yankees may exceed the estimated amounts, perhaps substantially. Included in the table above are future estimated billings that the Yankees made to their cost estimates beginning in the third quarter of fiscal 2003 and continuing through fiscal 2004 to reflect projected future security and insurance cost increases and other expenses. NEP’s share of these increases is approximately $162 million. Under settlement agreements, NEP is permitted to recover prudently incurred decommissioning costs through CTCs.

Decommissioning Collections: Each of the Yankees has established a trust fund, or escrow fund, to meet the projected costs of decommissioning. In order to collect the costs of decommissioning, from their purchasers (including NEP), the Yankees are required to file rate cases periodically with FERC. The rate filings present the Yankees’ estimates of future decommissioning costs for FERC approval. Yankee Atomic ceased decommissioning collections in June 2000. Subsequently, it filed for a rate increase, and received final approval from the FERC on October 2, 2003. Maine Yankee filed a rate case on October 20, 2003, and Connecticut Yankee filed a rate case on July 1, 2004.

Connecticut Yankee seeks a rate increase of approximately $76 million per year through 2010, of which NEP’s share would be approximately $15 million per year. This amount is included in the $162 million increase for all of the Yankees mentioned above. On June 10, 2004, the Connecticut Department of Public Utilities and the Connecticut Office of Consumer Counsel filed a petition with the FERC alleging that Connecticut Yankee’s management has been imprudent and asking the FERC to determine that if it should find that any of Connecticut Yankee’s decommissioning costs were not prudently incurred, the purchasers may not recover these costs in rates that are ultimately charged to distribution customers. Three other New England states have intervened in support of the state of Connecticut, as has Bechtel Power Corporation. Connecticut Yankee has opposed the petition, as have NEP and the other purchasers. NEP intends to contest the petition vigorously but cannot predict the outcome of this proceeding.

DOE Dispute: The Nuclear Waste Policy Act of 1982 establishes that the federal government, through the Department of Energy (DOE), is responsible for the disposal of spent nuclear fuel. In a lawsuit brought against the DOE by numerous utilities and state regulatory commissions, the U.S. Court of Appeals for the District of Columbia Circuit ruled in 1997 that the DOE was obligated to begin disposing of utilities’ spent nuclear fuel by January 1998. The DOE failed to meet this deadline. Many owners of nuclear power plants, including the Yankees, filed claims for money damages in the U.S. Court of Federal Claims for the costs associated with the DOE’s failure to begin to take fuel in 1998. In October 1998 the court held that the DOE is liable for such failure. The Yankees have filed a further action against the DOE to determine the level of damages. The trial began July 21, 2004. As an interim measure until the DOE meets its contractual obligations to dispose of the spent fuel, the Yankees have constructed independent spent fuel storage installations located at the plant sites.

Bechtel Dispute: On June 13, 2003, Connecticut Yankee terminated its firm fixed price contract with Bechtel Power Corporation, its decommissioning operations contractor, alleging various defaults of Betchel’s obligations. Bechtel has filed proceedings in Connecticut Superior Court against Connecticut Yankee alleging breach of contract and other claims, seeking compensatory and punitive damages and seeking garnishment of decommissioning trust funds and certain assets of Connecticut Yankee. Connecticut Yankee has filed a counterclaim against Bechtel and has stated that it intends to defend against Bechtel’s claims vigorously and to pursue its rights under the $36 million performance bond supplied by Bechtel’s surety, if necessary.  Following the contract termination, Connecticut Yankee commenced self-performance of the decommissioning work. As part of its transition into self-performance, Connecticut Yankee updated its 2003 cost estimate and filed a rate case as described above. This update includes the impact of Bechtel’s termination and reflects a substantial increase in cost and delay in the estimated completion date.

Divested Nuclear Units:

Vermont Yankee Nuclear Power Corporation (Vermont Yankee): NEP redeemed its 23.9 percent equity investment in Vermont Yankee on November 7, 2003. Vermont Yankee formerly owned the Vermont Yankee Nuclear Generating Station (the Station). It sold the Station to Entergy Vermont Yankee LLC (ENVY) in July 2002 for approximately $180 million. NEP’s portion of the sale price was approximately $43 million before settlement of Vermont Yankee’s outstanding liabilities. As part of the transaction, ENVY assumed the decommissioning liability for the Station. Following regulatory approvals and prior to the redemption of its stock on October 27, 2003, Vermont Yankee distributed to its owners, including NEP, a majority of the proceeds from the sale after payment of outstanding debt and other obligations. NEP received approximately $13 million in this distribution.

Vermont Yankee Missing Fuel Rod Segments: In April 2004, in response to an NRC inspection, which was conducted during the Station’s regularly scheduled refueling outage, ENVY determined that two spent nuclear fuel rod segments were not in their documented location in the spent fuel pool. Following an investigation of the matter, plant officials announced on July 13, 2004 that the missing fuel had been located in the Station’s spent fuel pool. According to station documentation, in 1979 the rods were placed in a special stainless steel container in the spent fuel pool.

ENVY has informed Vermont Yankee that it believes that Vermont Yankee is responsible under their Purchase and Sale Agreement for all costs arising in connection with ENVY's inspection.  On May 20, 2004 Vermont Yankee requested additional information from ENVY. The fuel has been located, and the expenditures made are not material to NEP.

Contracts for the Purchase of Electricity from ENVY: In connection with the sale of the Station, Vermont Yankee entered into a power contract with ENVY. Under an agreement between Vermont Yankee and NEP, NEP buys 22.5 percent of the entitlement of the Vermont Yankee generation until 2012. The Company has a contract with a third party to sell the entire 22.5 percent of the Vermont Yankee entitlement and recover 100 percent of its purchased power contract costs. The Company sells the power to the third party at its cost and thus does not recognize any financial impact from the agreement on its financial statements. The Company matches the cost of the power contract with the revenue from the sale of the power to the third party on its income statement. The Company’s commitments for future fiscal periods, under this purchased power contract as of March 31, 2004, are as follows: 2005, $44 million; 2006, $43 million; 2007, $45 million; 2008, $43 million; 2009, $45 million and 2010 and thereafter $157 million.

Hydro-Quebec Interconnection: Three affiliates of the Company were created to construct and operate transmission facilities to transmit power from Hydro-Quebec to New England. Under the financial and organizational agreements (the Support Agreements) entered into at the time these facilities were constructed, the Company agreed to guarantee a portion of the project debt. At June 30, 2004, the Company had guaranteed approximately $12 million of project debt with terms through 2015. As a result of the termination of an assignment of certain obligations under the Support Agreements on April 1, 2004, the Company recorded a capital lease with an offsetting liability of $38 million. The Company remains an obligor under the support agreements for the portion of the rights it transferred until 2020. See Note B for a discussion of the termination and the recovery of costs associated with these Support Agreements.

Hazardous Waste: The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for the costs to remediate property contaminated with hazardous substances. A number of states, including Massachusetts, have enacted similar laws.

The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. The Company currently has in place an internal environmental audit program and an external waste disposal vendor audit and qualification program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products.

The Company has been named as a potentially responsible party (PRP) by either the United States Environmental Protection Agency or the Massachusetts Department of Environmental Protection for several sites at which hazardous waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against the Company regarding hazardous waste cleanup. The Company is currently aware of other possible hazardous waste sites, and may in the future become aware of additional sites, that it may be held responsible for remediating. Some of these sites relate to the disposal of ash from fossil fuel generating plants formerly owned by the Company. Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. The Company has recovered amounts from certain insurers, and, where appropriate, intends to seek recovery from other insurers and from other PRPs, but it is uncertain whether, and to what extent, such efforts will be successful. The Company is currently recovering certain environmental cleanup costs in rates. The Company believes that hazardous waste liabilities for all sites of which it is aware are not material to its financial position.

Town of Norwood Dispute: NEP continues to be engaged in litigation in judicial and administrative forums with the Town of Norwood, Massachusetts. From 1983 until 1998, NEP was the wholesale power supplier for Norwood. In April 1998, Norwood began taking power from another supplier, although its contract term with NEP ran to 2008. Pursuant to a tariff amendment approved by the FERC in May 1998, NEP has been assessing Norwood a CTC. Through June 30, 2004, the charges assessed Norwood amount to approximately $83 million, approximately $20 million of which was paid in July 2004. The litigation with Norwood is as follows.

State Collection Action: NEP filed a collection action in Massachusetts Superior Court (Worcester County) to collect the CTC, which Norwood had refused to pay.  In March 2001, the Superior Court ruled that Norwood has breached the agreement by not paying the CTC charge, and ordered Norwood to make regular and substantial payments to an escrow account. Norwood unsuccessfully appealed the order to the Massachusetts Appeals Court, and the Massachusetts Supreme Judicial Court denied Norwood’s petition for further appellate review.  On June 1, 2004, the Supreme Court denied Norwood’s petition for certiorari.

On December 17, 2003, the Superior Court entered judgment for NEP for approximately $40.6 million, which included interest to that date, and which the Company subsequently moved to increase by approximately $2.7 million, to adjust for computational errors.  Norwood then moved to void the judgment, or stay its enforcement pending completion of the FERC proceeding described below, or both. On June 9, 2004, the Massachusetts Superior Court granted NEP’s motion to increase the judgment and denied Norwood’s motion to void the judgment or stay it pending Norwood’s Section 206 Proceeding at FERC. Norwood has asked the Superior Court to reconsider its grant of NEP’s motion and has appealed the judgment to the Massachusetts Appeals Court.   

FERC 206 Proceeding: In December 2002, Norwood filed a challenge to the CTC rate with the FERC under Section 206 of the Federal Power Act. Under this Section, the FERC has the power to grant prospective relief only. In an order dated July 2, 2003, the FERC set down for hearing Norwood’s challenge to the factors used to calculate the CTC rate for Norwood, and set a refund effective date of February 21, 2003, which empowers the FERC to direct NEP to adjust Norwood’s liability for unpaid charges billed after that date in the event that Norwood’s challenge is successful. On June 9, 2004, the FERC administrative law judge issued an initial decision recommending that FERC revise the CTC formula to reduce the CTC amount that was previously calculated under the formula which the FERC accepted and approved in 1998. On July 9, 2004, NEP filed a brief objecting to this initial decision. Norwood and the FERC staff have filed briefs which argue that the CTC rate recommended in the initial decision is too high.

Federal Court Antitrust Claim: In 1997, Norwood filed a lawsuit in the U.S. District Court for the District of Massachusetts challenging NEP’s proposed divestiture of its generating facilities. Following the District Court’s dismissal of all of Norwood’s claims, the U.S. Court of Appeals for the First Circuit reinstated Norwood’s claim that the sale to US Gen New England, Inc. (USGen) violated Section 7 of the Clayton Act on the ground that USGen had acquired market power. The First Circuit characterized the claim as weak because FERC had found no anticompetitive consequences from the sale, and invited the District Court to address whether the FERC’s decision precluded further litigation. This issue was argued to the District Court in 2001, but no decision has been rendered, in part because the original judge who heard argument subsequently recused herself. USGen’s bankruptcy filing on July 2, 2003 resulted in an automatic stay of this case.

Millstone 3 Prudence Challenge: In November 1999, NEP entered into an agreement with Northeast Utilities (NU) to settle certain claims. As part of the agreement, NU agreed to include NEP’s 16.2 percent ownership interest in Millstone Unit 3 in an auction of NU’s share of the unit. Upon the closing of the sale, NEP was to receive a fixed amount, regardless of the actual sale price. In March 2001, the Millstone units were sold, including NEP’s interest, for $1.3 billion. In accordance with the settlement agreement, NEP was paid approximately $27.9 million, from which NEP paid approximately $5.8 million to increase the decommissioning trust fund.

Regulatory authorities from Rhode Island, New Hampshire and Massachusetts have expressed intent to challenge the reasonableness of the settlement agreement, taking the position that NEP would have received approximately $140 million of sale proceeds if there had been no agreement with NU. On July 16, 2004, the New Hampshire Public Utilities Commission approved a settlement which will become final on August 16, 2004. The settlement provides that NEP will not have to adjust its contract termination charge to its New Hampshire distribution affiliate Granite State Electric Company as a result of NEP’s former ownership interest in Millstone 3. In the event that Rhode Island or Massachusetts or both states proceed with such a challenge, the dispute will be resolved by the FERC. Management believes that the Company acted prudently, because the amount it received under the settlement agreement was the highest sale price for a nuclear unit at the time the agreement was reached.

The Company’s reportable segments are electric transmission and electric other (primarily stranded cost recovery, see Note B – “Rate and Regulatory Issues”). The Company is engaged principally in the business of electric power transmission. Certain information regarding the Company's segments is set forth in the following table. General corporate expenses, property common to both segments and depreciation on such common property have been allocated to the segments based on labor or plant using a percentage derived from total labor or plant dollars charged directly to certain operating expense accounts or certain plant accounts. Corporate assets consist primarily of other property and investments, cash and unamortized debt expense.

As discussed in the Company’s Annual Report on Form 10-K for the year ended March 31, 2004 National Grid USA and its subsidiaries (including the Company), provide benefits to retirees in the form of pension and other postretirement benefits. The qualified defined benefit pension plans cover substantially all employees meeting certain minimum age and service requirements. Funding for the qualified defined benefit pension plans is based on actuarially determined contributions, the maximum of which is generally the amount deductible for income tax purposes and the minimum being that required by the Employee Retirement Income Security Act of 1974, as amended. The pension plans’ assets primarily consist of investments in equity and debt securities. In addition, National Grid USA and its subsidiaries (including the Company) sponsor non-qualified plans (plans that do not meet the criteria for tax benefits) that cover officers, certain other key employees, and non-employee directors. National Grid USA and its subsidiaries (including the Company) provide certain health care and life insurance benefits to retired U.S. employees and their eligible dependents. These benefits are subject to minimum age and service requirements. The health care benefits include medical coverage, dental coverage, and prescription drugs and are subject to certain limitations, such as deductibles and co-payments.

Benefit plans’ costs charged to the Company during the three months ended June 30, 2004 and 2003 included the following components:

This report and other presentations made by New England Power Company (the “Company”) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Throughout this report, forward looking statements can be identified by the words or phrases “will likely result”, “are expected to”, “will continue”, “is anticipated”, “estimated”, “projected”, “believe”, “hopes” or similar expressions. Although the Company believes that, in making any such statements, its expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to:

(a) the impact of further electric industry restructuring;

(b) federal and state regulatory developments and changes in law, which may have a substantial adverse impact on revenues or on the value of the Company’s assets;

(c) federal regulatory developments concerning regional transmission organizations;

(d) changes in accounting rules and interpretations, which may have an adverse impact on the Company’s statements of financial position and reported earnings;

(e) failure to recover costs currently deferred under the provisions Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulations”, as amended.

Certain critical accounting policies are based on assumptions and conditions that, if changed, could have a material effect on the financial condition, results of operations and liquidity of the Company. See the Company’s Annual Report on Form 10-K for the fiscal year ended March 31, 2004, Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Critical Accounting Policies” for a detailed discussion of these policies.

Net income for the quarter ended June 30, 2004, was not significantly different from the prior year and decreased by approximately $1 million as a result of decreased mitigation incentives and reduced return on CTCs compared with the same period in 2003. This decrease was partially offset by increased transmission earnings during the quarter as compared with the same period in 2003.

The Company has two primary sources of revenue: transmission and stranded investment recovery. Transmission revenues are based on a formula rate that recovers the Company’s actual costs plus a return on investment. Stranded investment recovery revenues are in the form of a CTC to former all-requirements customers of the Company in connection with the Company’s divestiture of its electric generation investments.

Operating revenue for the quarter ended June 30, 2004, increased approximately $3 million as compared to the same period in 2003 as a result of increased recovery of contract termination and nuclear unit shutdown charges.

OPERATING EXPENSES

Purchased power expense for the quarter ended June 30, 2004, increased approximately $3 million compared with the same period in 2003 due to decommissioning collections for Yankee Atomic Electric Company, which resumed in June 2003.

Operation and maintenance expense for the quarter ended June 30, 2004, increased approximately $2 million compared with the same period in 2003. The primary reason for the increase was increased transmission wheeling expenses.

At June 30, 2004 the Company’s principal sources of liquidity included cash and cash equivalents of approximately $253 million and accounts receivable of $165 million. The Company has a working capital balance of approximately $327 million.

Net cash flows provided by operating activities for the quarter ended June 30, 2004, was approximately $33 million.

Net cash flows used in investing activities for the quarter ended June 30, 2004, increased approximately $1 million compared with the same period in 2003, primarily due to increased plant expenditures.

At June 30, 2004, the Company had no short-term debt outstanding. The Company has regulatory approval to issue up to $375 million of short-term debt. National Grid USA and certain subsidiaries, including the Company, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies that invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice.

At June 30, 2004, the Company had lines of credit and standby bond purchase facilities with banks totaling $439 million which is available to provide liquidity support for $410 million of the Company’s long-term bonds in tax-exempt commercial paper mode, and for other corporate purposes. The Company's line of credit expires and is renewed each December. The Company's standby bond purchase facility expires and is renewed each September. There were no borrowings under these lines of credit at June 30, 2004. Fees are paid on the lines and facilities in lieu of compensating balances.

Utility Plant Expenditures: Cash expenditures for the Company for utility plant totaled approximately $9 million for the quarter ended June 30, 2004, and were primarily transmission-related. The funds necessary for utility plant expenditures during the period were primarily provided by internal funds.

Rate Filing: As discussed in more detail in the Company’s Form 10-K for the fiscal year ended March 31, 2004, on March 24, 2004 FERC issued an order approving for regional network service rates (RNS) a 0.5% return on equity adder for joining a proposed Regional Transmission Organization (RTO) effective as of the date that the RTO commences operation. NEP would earn this additional return on equity (ROE) provided it joins the RTO. Approximately seventy percent of the company’s transmission costs are recovered through RNS rates. FERC also suspended a proposed increase to 12.8% of the base ROE for both RNS and Local Network Service rates and a 1% adder for new transmission investment recovered through RNS rates subject to refund effective as of the RTO operations date. The issues concerning the base ROE for both RNS rates and LNS rates and the 1% adder for new transmission investment recovered through RNS rates have been set for an evidentiary hearing in December 2004. The Connecticut Department of Public Utility Control and some transmission customers have intervened in the proceeding. On July 30 these interveners filed testimony advocating for a base return on equity ranging from approximately 8.5% to 9.5%, and against the 1% adder for new transmission investment.

The transmission owners on April 15, 2004 filed a motion for clarification with FERC on three issues that were addressed in the March 24 order. Each of these issues concerns the amount of revenues that transmission owners would receive once the RTO commences operations.

Interest Rate Risk: The Company’s major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable rate debt. At June 30, 2004, the Company’s tax exempt variable rate long-term debt had a carrying value of approximately $410 million. While the ultimate maturity dates of the underlying loan agreements range from 2015 through 2022, this debt is issued in tax exempt commercial paper mode. The various components that comprise this debt are issued for periods ranging from one day to 270 days, and are remarketed through remarketing agents at the conclusion of each period. The weighted average variable interest rate for the quarter ended June 30, 2004, was approximately 1.17 percent.


ITEM 4.     CONTROLS AND PROCEDURES

The Company has carried out an evaluation under the supervision and with the participation of its management, including the Chief Financial Officer and President, of the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on and as of that evaluation, it was determined that these disclosure controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports that the Company files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required.

During the most recent fiscal quarter, the Company completed implementation of a new enterprise resource planning and information system to integrate its finance and accounting, supply chain and work management information systems. The implementation of this new system has resulted in new processes for recording the underlying transactions of the Company’s financial statements. As such, the Company’s internal controls have been modified to encompass these new processes.

PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS

Millstone 3 Prudence Challenge: As described in the Company’s Form 10-K for the fiscal year ended March 31, 2004, regulatory authorities from Rhode Island, New Hampshire and Massachusetts have expressed intent to challenge the reasonableness of the Company’s settlement agreement with Northeast Utilities, under which NEP received a fixed amount when the Millstone units were sold in 2001. On July 16, 2004, the New Hampshire Public Utilities Commission approved a settlement which will become final on August 16, 2004. The settlement provides that NEP will not have to adjust its contract termination charge to its New Hampshire distribution affiliate Granite State Electric Company as a result of NEP’s former ownership interest in Millstone 3.


ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

As reported in the Company’s Form 10-K for the fiscal year ended March 31, 2004, the Annual Meeting of Stockholders was held on April 21, 2004. By a vote of 3,619,906 shares out of 3,632,630 total shares voted, the following actions were taken:

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report on Form
10-Q for the quarter ended June 30, 2004 to be signed on its behalf by the undersigned thereunto duly authorized.