FORM 10-Q

For the quarterly period ended September 30, 2004

For the transition period from __________ to __________

NEW ENGLAND POWER COMPANY

FORM 10-Q - For the Quarter Ended September 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 September 30
(In thousands of dollars)
(UNAUDITED)

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.

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NEW ENGLAND POWER COMPANY
Condensed Balance Sheets
(In thousands of dollars)
(UNAUDITED)

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

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NEW ENGLAND POWER COMPANY
Condensed Balance Sheets
(In thousands of dollars)
(UNAUDITED)

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

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NEW ENGLAND POWER COMPANY
Condensed Statements of Cash Flows
Periods Ended September 30
(In thousands of dollars)
(UNAUDITED)

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

NEW ENGLAND POWER COMPANY
Notes to Unaudited Financial Statements

NOTE A — SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation: New England Power Company (the Company or NEP), in the opinion of management, has included all adjustments (which include normal recurring adjustments) necessary for a fair statement of the financial position and results of 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.

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

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

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.

In May 2004, the Financial Accounting Standards Board issued Staff Position 106-2 (FAS 106-2) providing final guidance on accounting for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Company adopted the provisions of FAS 106-2 on July 1, 2004. The Company recorded the effects of the subsidy in measuring its net periodic postretirement benefit cost for the three months ended September 30, 2004. This resulted in a reduction of $7 million in the Company's accumulated postretirement benefit obligation (APBO) for the subsidy related to benefits attributed to past service. The subsidy resulted in a reduction of $213,000 in the Company's current period net periodic postretirement benefit costs for the three months ended September 30, 2004, which will be credited to customers. See Note E – “Employee Benefits.”


NOTE B — RATE AND REGULATORY ISSUES

The Company’s financial statements conform to generally accepted accounting principles in the USA (GAAP), including the accounting principles for rate regulated entities with respect to its regulated operations. 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 approved by the appropriate commissions, 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 net regulatory assets for the costs that are recoverable from customers through CTCs. At September 30, 2004 and March 31, 2004 this amounted to approximately $1.0 billion and $1.1 billion, respectively, including $0.6 billion and $0.6 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 USGen 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 September 30, 2004 and March 31, 2004, the net present value of the liability for the fixed monthly payment was approximately $351 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 corresponding regulatory asset for the above-market cost of the contracts from its balance sheet. At September 30, 2004, the Company’s capitalized cost of the above-market portion of the Contracts that are with USGen was approximately $290 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 CTCs from its customers.

In September 2004, USGen asked the bankruptcy court to approve bidding procedures for the proposed sales of three former NEP-owned fossil generating units and its hydroelectric generating units. In neither transaction would the buyer assume certain integrated contracts, including the Transfer Agreement. NEP has opposed the bidding procedures in both sales. Management cannot predict the outcome of the bankruptcy proceeding or the likelihood or amount of NEP’s recovery on any claims or potential claims against USGen.



NOTE C — COMMITMENTS AND CONTINGENCIES

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. Future Estimated Billings listed in the table above include increases 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 increases in security and insurance costs 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 received final approval from the FERC on September 16, 2004. Connecticut Yankee filed a rate case with the FERC on July 1, 2004, seeking 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.

Intervention in Connecticut Yankee Rate Filing: The Connecticut Department of Public Utility Control and the Connecticut Office of Consumer Counsel (together, the Department) intervened at FERC requesting that FERC reject Connecticut Yankee’s rate filing, or in the alternative, disallow a portion of the requested rate increase on the ground that certain of the costs were imprudently incurred. Bechtel Power Corporation and three New England states have also intervened, asserting that certain of these costs are imprudent and should be disallowed. FERC has accepted Connecticut Yankee’s rate filing and suspended the effectiveness of the proposed new rates until February 1, 2005, to be collected subject to refund.

Challenge to Connecticut Yankee Recovery: On June 10, 2004, before Connecticut Yankee filed its rate case with the FERC, the Department filed a petition with the FERC 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. In an order dated August 30, 2004, FERC denied the Department’s petition on the grounds that it has no jurisdiction over retail rates and that only prudently incurred costs are recoverable under wholesale power contracts. The Department and Bechtel have filed motions for clarification and rehearing.

Bechtel Dispute: On June 13, 2003, Connecticut Yankee terminated its firm fixed price contract with Bechtel, its decommissioning operations contractor, alleging various defaults of Bechtel’s obligations. Bechtel has filed a lawsuit in Connecticut Superior Court against Connecticut Yankee alleging breach of contract and other claims, seeking compensatory and punitive damages. Connecticut Yankee has filed a counterclaim against Bechtel seeking damages, including the recovery of a performance bond supplied by Bechtel’s surety, and has stated that it intends to defend against Bechtel’s claims vigorously.  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 decommissioning cost estimate and filed a rate case as described above. The rate case reflects the impact of Bechtel’s termination and projects a substantial increase in cost and delay in the estimated completion date.

In July 2004, Bechtel had sought in Connecticut Superior Court to garnish the decommissioning trust funds and certain assets of Connecticut Yankee. In October 2004, Bechtel and Connecticut Yankee stipulated that they may litigate whether Bechtel can garnish Connecticut Yankee’s assets not committed to decommissioning, and Bechtel waived its right to seek to garnish the decommissioning funds.

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, which is now pending. 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.

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 September 30, 2004, the charges assessed Norwood but not paid amount to approximately $67.5 million. Norwood made a payment of approximately $20 million in July 2004. The litigation with Norwood is continuing and 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 hearings are scheduled for November. Norwood has also 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 agreed 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, NEP was paid approximately $25 million for its interest in the unit (plus reimbursement of pre-paid amounts), from which NEP paid approximately $6.2 million to increase the decommissioning trust fund.

In the past, regulatory authorities from Rhode Island, New Hampshire and Massachusetts expressed an intent to challenge the reasonableness of the settlement agreement on various grounds, 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 is now final. 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 a challenge, the dispute will be resolved by the FERC. Management believes that the Company acted prudently, because, among other reasons, the amount it received under the settlement agreement was the highest sale price for a nuclear unit at the time the agreement was reached.

NOTE D — SEGMENTS

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. Corporate assets consist primarily of other property and investments, cash and unamortized debt expense.

NOTE E - EMPLOYEE BENEFITS

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 and six months ended September 30, 2004 and 2003 included the following components:

As described in Note A, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) introduced a prescription drug benefit under Medicare Part D and a federal subsidy to sponsors of retirement health care plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In May 2004, the FASB issued Staff Position 106-2, providing final guidance on accounting for the Act. The Company recorded the effects of the subsidy in measuring net periodic postretirement benefit cost for the three months ended September 30, 2004. This resulted in a reduction of $7 million in the accumulated postretirement benefit obligation (APBO) for the subsidy related to benefits attributed to past service. The subsidy resulted in a reduction of $213,000 in the Company’s current period net periodic postretirement benefit costs for the three months ended September 30, 2004, which will be credited to customers.

The net periodic benefit costs charged to the Company during the three months ended September 30, 2004 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) the impact of general economic changes;

(c) 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;

(d) federal regulatory developments concerning regional transmission organizations;

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

(f) timing and adequacy of rate relief;

(g) adverse changes in electric load;

(h) acts of terrorism;

(i) climatic changes or unexpected changes in weather patterns; and

(j) 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 and six months ended September 30, 2004, decreased by approximately $2 million and $3 million, respectively, compared with the same periods in 2003. The reduction was due primarily to decreased mitigation incentives, reduced revenues from the Town of Norwood (see Note C), and a declining stranded investment base resulting in reduced returns. This decrease was partially offset by an increase of transmission earnings as investment in transmission plant increases.

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 Contract Termination Charge (CTC), which is billed 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 September 30, 2004, decreased approximately $3 million and remained relatively unchanged for the six months, compared to the same periods in 2003. The second quarter decrease of $3 million included reduced recovery of lower transmission maintenance expense, lower Norwood revenues, temporary decreases in nuclear decommissioning bills, and scheduled reductions in purchased power recoveries. These items were partially offset by increased recoveries of wheeling costs. Operating revenue for the six month period was relatively unchanged since recoverable expense increases described below were essentially offset by reduced Norwood revenues.

OPERATING EXPENSES

Purchased power expense for the quarter and six months ended September 30, 2004, decreased approximately $4 million and $1 million, respectively, compared with the same periods in 2003. The second quarter purchased power decrease of $4 million was primarily attributed to scheduled reductions in purchased power obligation payments and temporary decreases in nuclear decommissioning costs. The six month purchased power decrease of $1 million included increased nuclear decommissioning costs offset by reductions in purchased power obligation payments.

Operation and maintenance expense for the quarter and six months ended September 30, 2004, increased approximately $1 million and $3 million, respectively, compared with the same periods in 2003. The primary reason for the increase was the resumption of support payments under the Hydro Quebec transmission line agreements (see Note B), offset by decreased transmission maintenance costs.

At September 30, 2004 the Company’s principal sources of liquidity included cash and cash equivalents of approximately $294 million and accounts receivable of $146 million. The Company has a positive working capital balance of approximately $348 million.

Net cash flows provided by operating activities increased approximately $11 million for the six months ended September 30, 2004 compared with the same period in 2003. Cash improved from operating results due to the collection of a receivable in the amount of $20 million from the Town of Norwood in fiscal year 2005 and a purchased power buyout of $13 million in fiscal year 2004. This increase in cash receipts was partially offset by a $13 million increase in cash payments for taxes during the six months ended September 30, 2004.

Net cash flows used in investing activities for the six months ended September 30, 2004, increased approximately $7 million compared with the same period in 2003, due to increased plant expenditures.

At September 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 September 30, 2004, the Company had line of credit and standby bond purchase facilities with banks totaling $439 million which are available to provide liquidity support for $410 million of the Company’s long-term bonds, and for other corporate purposes. The Company’s line of credit expires in December. The Company’s standby bond purchase facility is also scheduled to expire in December. Prior to the expiration of these agreements, the Company intends to replace them with comparable new bank facilities. There were no borrowings under these facilities at September 30, 2004. Fees are paid on the facilities in lieu of compensating balances.

Utility Plant Expenditures: Cash expenditures for the Company for utility plant totaled approximately $26 million for six months ended September 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 (RNS) rates 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 (LNS) 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 were set for an evidentiary hearing. On April 15, transmission owners filed a motion asking FERC to affirm as reasonable the methodology that transmission owners had used to develop their proposed base ROE level. Specifically, the transmission owners asked FERC to confirm that the ROE should be established based on the midpoint return using a discounted cash flow analysis of a proxy group of northeast utility companies. On November 3, FERC issued an order clarifying that this methodology is the appropriate one to use to determine base ROE. FERC also clarified that transmission owners may revise transmission tariff language to clarify that shareholders rather than customers should obtain the benefit of the 0.5% ROE adder that had previously been approved. Finally, the FERC set for hearing an issue concerning the types of new investment that should qualify for the 1% ROE adder.

Prior to the FERC’s recent order, certain intervenors and FERC Staff had filed testimony arguing for a base ROE in the range of 8.5% to 10.1%. The positions of the intervenors and FERC Staff were based on methodologies different from the methodology that the FERC endorsed in its November 3 order, however. On October 31, 2004, the transmission owners filed testimony updating their base ROE proposal to reflect current market conditions. The testimony revised the transmission owners’ proposed base ROE to 11.1%. A hearing on the outstanding ROE issues is scheduled to commence in December 2004.

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 September 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 and six months ended September 30, 2004, were approximately 1.30 percent and 1.24 percent, respectively.

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.

No change in internal control over financial reporting occurred during the fiscal quarter ended September 30, 2004 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Millstone 3 Prudence Challenge: As described in the Company’s 10-K for the fiscal year ended March 31, 2004 and its 10-Q for the quarter ended June 30, 2004, in the past, regulatory authorities from Rhode Island, New Hampshire and Massachusetts expressed an 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 is now final. 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.

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 September 30, 2004 to be signed on its behalf by the undersigned thereunto duly authorized.