X   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Forward-Looking information: This report and other presentations made by New England Power Company (NEP or 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 NEP 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 industry restructuring, as more fully set out under Regulatory Environment below;

(b) The impact of general economic changes in New England;

(c) Federal and state regulatory developments and changes in law which may have a substantial adverse impact on revenues or on the value of NEP’s assets;

(d) Federal regulatory developments concerning regional transmission organizations, as more fully set out under Regulatory Environment and Transmission Properties below;

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

(f) Timing and adequacy of rate relief;

(g) Adverse changes in electric load;

(h) Climatic changes or unexpected changes in weather patterns; and

(i) Failure to recover operation and decommissioning costs associated with nuclear generating facilities, as set out under Note D in Item 8. Financial Statements and Supplementary Data.

PART I

THE COMPANY

(a) For information on the Company’s ownership interests in nuclear generating units, see Item. 8 Financial Statements and Supplementary Data.

The facilities of NEP, together with the four New England electricity delivery companies, constitute an electrical transmission and distribution system that is directly interconnected with other utilities in New England and New York State, and indirectly interconnected with utilities in Canada

Acquisition of EUA: The acquisition of Eastern Utilities Associates (EUA) by National Grid USA was completed on April 19, 2000. On May 1, 2000, Montaup Electric Company (Montaup), formerly a subsidiary of EUA, was merged into the Company.

At March 31, 2003, NEP had 7 employees, 6 of whom are members of the labor organization, the International Brotherhood of Electrical Workers.

Description of Business: The Company’s primary business is the transmission of electric energy to other electric utilities, principally its four New England distribution affiliates. NEP owns a system of transmission lines and substations. The Company continues to own minority equity interest in four nuclear power companies, none of which owns any operating nuclear units. The Company sold its 10 percent interest in a jointly held nuclear generating plant in November 2002. Additionally, the Company owns a nine percent interest in the Wyman 4 fossil fuel plant located in Yarmouth, Maine.

Purchased Power Transfer Agreement: As part of the sale of the Company’s nonnuclear generating business to USGen New England, Inc. (USGen) , a wholly owned subsidiary of PG&E, in 1997, NEP signed a purchased power transfer agreement through which USGen purchased the Company’s entitlement to approximately 1,100 MW of power procured under long-term contracts. In the ensuing period, contract terminations, assignments and expirations have reduced this entitlement to approximately 580 MW. For more information, see Item 8. Financial Statements and Supplementary Data.

Segments: The Company's reportable segments are electric transmission and electric distribution. The Company is engaged principally in the business of electric power transmission. For more information, see Item 8. Financial Statements and Supplementary Data.

Financial Information about Geographic Regions: NEP’s business is primarily the transmission of electric energy in wholesale quantities to other electric utilities, principally its distribution affiliates, National Grid USA’s four New England electricity delivery companies which are located in Massachusetts, New Hampshire and Rhode Island: Massachusetts Electric Company, Nantucket Electric Company, the Narragansett Electric Company and Granite State Electric Company. All of the Company customers and assets are concentrated in the northeast region of the United States. For more information, see Item 8. Financial Statements and Supplementary Data.

Regulation: Numerous activities of the Company are subject to regulation by various federal agencies. Under the 1935 Act, many transactions of the Company are subject to the jurisdiction of the SEC. Under the Federal Power Act, the Company is subject to the jurisdiction of the FERC with respect to rates and accounting. In addition, the NRC has broad jurisdiction over nuclear units and federal environmental agencies have broad jurisdiction over environmental matters. For more information, see Item 8. Financial Statements and Supplementary Data.

Environmental Requirements: The Company is subject to federal, state, and local environmental regulation of, among other things, wetlands and flood plains; air and water quality; storage, transportation, and disposal of hazardous wastes and substances; underground storage tanks; and land-use. For more information, see Item 8.Financial Statements and Supplementary Data.

ISO 14001: In June 2001, the Company announced that its transmission business achieved ISO (International Organization of Standardization) 14001 registration of its Environmental Management System, the first linear electric utility system in the country to achieve such designation. This also marked the first ISO 14001 registration of a high-voltage direct current (HVDC) transmission system in the U.S. The registration certifies that all activities, products, and services required to operate, maintain, and construct transmission lines, rights-of-way, HVDC converter terminals, and vegetation management activities meet the requirements of the internationally accepted ISO 14001 environmental standard.

ITEM 2. PROPERTIES

The Company’s integrated system consists of approximately 2,800 circuit miles of transmission lines, and approximately 120 substations.

The properties of the Company also include the ownership interests of New England Electric Transmission Corporation (NEET), New England Hydro-Transmission Electric Company, Inc. (Mass. Hydro), and New England Hydro-Transmission Corporation (N.H.Hydro) in the Hydro-Quebec Interconnection, and an integrated system of transmission lines, substations, and distribution facilities.

The Company is a participant in the New England Power Pool (NEPOOL). The NEPOOL Agreement provides for coordination of the operation of the generation and transmission facilities of its members. The NEPOOL Agreement further provides for New England-wide central dispatch of generation by the Independent System Operator (ISO).

ISO New England was activated on July 1, 1997 and has been operating the control area since that time. It operates under contract with NEPOOL and is governed by an independent board of directors. NEPOOL’s Open Access Transmission Tariff, which covers service across pool transmission facilities, is administered by ISO New England.

In May 1999, NEPOOL and ISO New England began implementing the NEPOOL competitive market system. The market system establishes markets for several tradable energy and reserve products. Implementation of the markets also has resulted in the imposition of certain costs including congestion related costs. By Order issued June 28, 2000, FERC conditionally approved a congestion management system and multi-settlement system (CMS/MSS). The CMS/MSS includes a Financial Transmission Rights scheme, a transmission planning process, and locational marginal pricing. The Standard Market Design (SMD) which was implemented on March 1, 2003 is based on the market system presently in place in the PJM (Pennsylvania, New Jersey, Maryland) interconnection and in New York, and is intended to bring greater consistency to power markets in the Northeast.

NEPOOL’s governance structure consists of five sectors: transmission owners, generators, suppliers, public power, and end users. National Grid USA participates in the transmission owners sector. The transmission sector accounts for 20 percent of the NEPOOL vote and the National Grid USA Companies account for one-seventh of the transmission sector vote. Under NEPOOL’s revised governance structure, all National Grid USA companies are considered “related persons” and therefore receive only a single vote.

Interconnection with Quebec: NEET owns and operates a portion of an international transmission interconnection between the electric systems of Hydro-Quebec and New England. Mass. Hydro and N.H. Hydro own and operate facilities in connection with an expanded second phase of this interconnection. New England Hydro Finance Company, Inc. (N.E. Hydro Finance) provides the debt financing to Mass. Hydro and N.H. Hydro for the capital costs of the interconnection. National Grid USA owns 100% of the voting stock of NEET and 57.47% of the voting stock of both Mass. Hydro and N.H. Hydro. Mass. Hydro and N.H. Hydro each own 50% of the voting securities of N.E. Hydro Finance.

NEET, Mass. Hydro, and N.H. Hydro own and operate a 450 kV direct current transmission line and related terminals to interconnect the New England and Quebec transmission systems (the Interconnection). The transfer capability of the Interconnection is currently rated at 2,000 megawatts (MW). Operating limits implemented by adjacent Power Pools covering New York, New Jersey, Pennsylvania, and Maryland often restrict the effective transfer capability to levels of 1,200 MW to 1,400 MW.

The Interconnection has two phases. The Company’s participation in both is approximately 22 percent. The Company and the other participants have entered into support agreements that end in 2020. Under the support agreements, NEP has agreed to guarantee its share of debt financing for the second phase. At March 31, 2003, the Company guaranteed approximately $18 million of project debt, including $3 million originally guaranteed by Montaup, with terms through 2015. NEP’s rights and obligations under its support agreements were transferred to the purchaser of its nonnuclear generation, but NEP retained Montaup’s rights and obligations under its support agreement. NEP remains an obligor under the support agreements, for the portion of the rights it transferred until 2020. Costs associated with these support agreements are recoverable through the Company’s transmission rates.

ITEM 3. LEGAL PROCEEDINGS

Millstone 3 Prudence Challenge: In November 1999, NEP entered into an agreement with Northeast Utilities (NU) to settle certain claims. Among other things, the settlement agreement required NU 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 the decommissioning trust fund.

Regulatory authorities from Rhode Island, New Hampshire and Massachusetts have expressed intent to challenge the reasonableness of the settlement agreement, on the ground that NEP would have received approximately $140 million of sale proceeds if there had been no agreement with NU. In the event that one or more of the states proceed with such a challenge, the dispute will be resolved by the FERC. NEP believes it has a strong argument that it acted prudently, as the amount it received under the settlement agreement was the highest sale price for a nuclear unit at the time the agreement was reached.

Town of Norwood Litigation: NEP continues to be engaged in litigation in judicial and administrative forums with the Town of Norwood (Norwood), Massachusetts, which was an all-requirements customer of NEP from 1983 to 1998. The contract term ran to 2008, and Norwood announced its intention to terminate the contract prematurely in response to NEP’s planned sale of its generating facilities to USGen New England, Inc. (USGen). NEP responded to Norwood’s proposed termination by filing a Contract Termination Charge (CTC) at the FERC. The litigation is as follows:

State Collection Action: NEP filed a collection action in Massachusetts Superior Court (Worcester County) to collect the CTC charge, which Norwood has refused to pay. Through March 31, 2003, NEP’s billings are approximately $59 million, including late payment charges, which run at 1.5% per month on the unpaid balance. 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 (which today contains about $23 million). Norwood appealed the judgment, oral argument took place in March 2003 and the parties are awaiting a decision.

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 (unless the rate was computationally flawed from the outset). Norwood has the burden of proof. NEP has moved to dismiss the proceeding and alternatively, to delay proceedings until Norwood pays NEP its full CTC. In a draft order released on or about June 25, 2003, FERC granted NEP's motion to dismiss those portions of Norwood's complaint under Section 206 of the Federal Power Act that Norwood previously litigated before FERC and the federal district court, and set down for hearing Norwood's challenge to the factors that are used to calculate the CTC rate. In so doing, the FERC set a refund date of February 21, 2003 and referred the matter initially to a FERC settlement judge, consistent with its normal procedures. The draft order is subject to further modification by FERC before it is issued in final form.

Federal Court Antitrust Claim: In 1997, Norwood filed a lawsuit in federal district court in Boston challenging NEP’s proposed divestiture of its generating facilities. Following the district court’s dismissal of all of its claims, the First Circuit Court of Appeals reinstated Norwood’s claim that the sale to 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 in light of the fact that 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.

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

On February 20, 2003, a Special Meeting of Shareholders was held. By unanimous vote of the 3,619,896 shares present of 3,632,846 total shares having general voting rights:

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS

The common stock of NEP is held solely by National Grid USA, and therefore indirectly by National Grid Transco plc. There is no public trading market for the Company’s common stock, and the Company sold no equity securities during the period covered by this Annual Report. For information about the Company's payment of dividends and restrictions on those payments, see Item 6, Selected Financial Data, and Item 8.Financial Statements and Supplementary Data, Note I.


ITEM 6. SELECTED FINANCIAL DATA

The following tables set forth selected financial information for NEP for the years ended March 31, 2003, 2002, and 2001, respectively, and for the years ended December 31, 1999 and 1998, respectively, and for the three months ended March 31, 2000 and 1999, respectively, which have been derived from the financial statements of NEP and should be read in connection therewith.

On March 22, 2000, the Company’s former parent New England Electric Systems merged with National Grid Transco plc (formerly National Grid Group plc) in a purchase business combination recorded under the “push-down” method of accounting, resulting in a new basis of accounting for the “successor” period beginning March 22, 2000. Information relating to all “predecessor” periods prior to the acquisition is presented using the Company’s historical basis of accounting. The following selected financial data for the Company may not be indicative of the Company’s future financial condition, results of operations or cash flows.

** All of NEP’s shares of common stock are owned by its parent company therefore, per share data is not relevant.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

FERC Proceedings: The FERC is contemplating major changes to the regulatory structure that governs the Company’s business. Several proposals are under consideration, any of which may affect how the Company does business. The Company cannot predict which or how many of the proposals the FERC will adopt or in what form, or whether they will have a material impact on the Company’s financial position or results of operations.

Regional Transmission Organizations: Transmission owners, including the Company, have been working to develop an alternative Regional Transmission Organization (RTO) structure. It is not clear what structure will emerge from these negotiations. In August 2002, the New York and New England ISOs filed a proposal with the FERC to form an RTO but withdrew it in November 2002 after several parties, including National Grid USA, filed protests. Currently, the Company is working with stakeholders in New England to develop a proposal for a New England–only RTO or an ISO that complies with FERC’s standard market design principals. Such a proposal is expected to be filed in October 2003.

Standard Market Design: In July 2002, the FERC issued a formal notice of proposed rulemaking (NOPR) on standard market design (SMD). The proposed rules address transmission pricing and planning, the role of merchant transmission, and other issues that would directly affect the Company. The FERC issued a White Paper on April 28, 2003 outlining a proposed wholesale power market platform that it would require in any final rules in this proceeding. The White Paper embodies FERC's response to the comments that it received in this proceeding. FERC states that it intends to issue a rule requiring that every public utility join an independent entity (either an RTO or an ISO) that would be responsible for transmission service, tariff design, system operations and markets within a region. States would have a significant role in regional transmission planning, tariff design and in ensuring resource adequacy. Transmission owners that are market participants would have limited authority to manage transmission. Independent transmission companies may manage a broader set of functions. In addition, to the extent the Company wishes to pursue opportunities related to transmission projects, the FERC rulings in the SMD proceeding and other proceedings may limit the Company's ability to do so.

On July 12, 2002, the U.S. Court of Appeals issued an order concerning Pennsylvania-New Jersey-Maryland ISO’s relationship with its transmission owners. This order was favorable precedent to the Company because it suggested that transmission owners that join ISOs still maintain significant authority to propose transmission rates and to withdraw from such ISOs. On December 19, 2002 and May 14, 2003, however, the FERC issued decisions that appear to narrow this authority. On May 20, 2003 the U.S. Court of Appeals issued a ruling declaring that the FERC’s December 19, 2002 order had violated the Court’s mandate. It is not clear whether the FERC’s decision will stand, but the uncertainty surrounding this issue will likely affect the Company’s relationship with ISO New England and with any future RTO. Currently the Company, other transmission owners and ISO New England is seeking to work out mutually agreeable arrangements that would govern the relationship between transmission owners and the RTO/ISO as part of the anticipated RTO/ISO filing to be made in October 2003.

The New England Power Pool (NEPOOL) and ISO New England have a separate SMD initiative that is proceeding in parallel to the FERC initiative. The New England SMD was implemented on March 1, 2003.

Standards of Conduct: In September 2001, the FERC initiated a NOPR regarding affiliate standards of conduct in both the electric and gas industries. In its proposed rules, the FERC proposed a broad definition of "energy affiliate," which would include the Company’s affiliate National Grid USA Service Company, Inc., as well as the Company’s electric distribution company affiliates. If the FERC were to adopt these rules as proposed, the Company would have to change the way it interacts with its so-called energy affiliates in a manner that could increase costs.

Incentive Pricing: In January 2003, the FERC proposed a pricing policy statement indicating that it may provide incentives to transmission owners to join a RTO, an independent transmission company and to invest in new facilities. The FERC has solicited comments on this statement, and the Company cannot predict what the final policy statement will say or whether it will have a material impact on the Company’s financial position or results of operations.

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. The following accounting policies are particularly important to the financial condition and results of operations of the Company: regulatory accounting, goodwill accounting and pensions.

Regulatory Accounting: 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. In 1997, the Emerging Issues Task Force of the FASB concluded that a utility that had received approval to recover stranded costs through regulated rates would be permitted to continue to apply FAS 71 to the recovery of stranded costs.

The Company has received authorization from the FERC to recover through CTCs substantially all of the costs associated with its former generating business not recovered through the divestiture. Additionally, FERC Order No. 888 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.

As a result of applying FAS 71, the Company has recorded a regulatory asset for the costs that are recoverable from customers through the CTC. At March 31, 2003 and 2002, net regulatory assets amounted to approximately $1.3 billion and $1.4 billion, respectively, including $0.8 billion and $1.0 billion, respectively, related to the above-market costs of purchased power contracts, $0.3 billion and $0.2 billion, respectively, related to accrued Yankee nuclear plant costs, and $0.2 billion and $0.2 billion, respectively, related to other net CTC regulatory assets.

Goodwill: The company applies the provisions of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets” (FAS 142). In accordance with FAS 142, goodwill must be reviewed for impairment at least annually. The Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the performance of the annual goodwill impairment test. The result of the annual analysis determined that no adjustment to the goodwill carrying value was required.

Pensions: The Company has recognized an additional minimum pension liability of $94 million on its balance sheet reflecting this under funded pension obligation.  However, due to the nature of its rate plan the Company has not charged other comprehensive income but has instead recorded a regulatory asset. 

Net income for the twelve months ended March 31, 2002 increased approximately $18 million compared with the same period in 2001. The increase is primarily due to the adoption of Statement of Financial Accounting Standards No. 142 “Accounting for Goodwill and Other Intangible Assets” (FAS 142), effective April 1, 2001, which required the cessation of goodwill amortization (see Note A-8). Also contributing to the increase in earnings is a decrease in interest expense due to decreased interest rates on variable-rate long-term debt and the refinancing of short-term debt.

REVENUES

Operating revenue: In the fiscal year ended March 31, 2003, the Company was no longer receiving revenue related to its obligation to provide electric supply to serve certain customers of The Narragansett Electric Company, an affiliate. Effective December 1, 2001, the Company was no longer obligated to provide this power to Narragansett's customers, which is the primary reason for the decrease in revenues for the year ended March 31, 2003 of approximately $46 million. In addition, revenue decreased as a result of reduced sales of power purchased from the Vermont Yankee Nuclear Generating Station (Vermont Yankee) which was sold in July 2002. The decrease in revenues was partially offset by an increase in nuclear revenues, due to the recovery of a portion of increased nuclear operating expenses and increased transmission revenue compared with the same period in 2002.

Operating revenue for the twelve months ended March 31, 2002, decreased approximately $96 million compared with the same period in 2001. The decrease is primarily attributable to reduced kilowatt-hour (kWh) sales due to the sale of the Millstone 3 nuclear generating unit and the effect of a refueling outage at the Vermont Yankee nuclear power plant during the year. The decrease is also related to reduced CTC revenue due to fully reconciling true-up mechanisms that allow the Company to adjust revenues proportionately with correlating expenses. Partially offsetting these decreases were increased transmission revenues.

OPERATING EXPENSES

Operating expenses for the twelve months ended March 31, 2003 and 2002 decreased approximately $41 and $94 million, respectively, compared with the same periods in the preceding fiscal years. The following paragraphs describe the respective decreases.

Fuel for generation expense for the twelve months ended March 31, 2003 increased approximately $3 million, compared with the same period in 2002 due to increased fuel expense at the Wyman 4 plant. Fuel for generation expense for the twelve months ended March 31, 2002 decreased approximately $6 million, primarily due to the sale of Millstone 3 and decreased fuel expense at the Wyman 4 plant.

Purchased power expense for the fiscal year ended March 31, 2003, decreased approximately $51 million compared with the same period in 2002. The decrease was primarily caused by the termination of the company’s obligation to provide power to Narragansett Electric Company as described in Operating Revenue, above. In addition, purchased power expense decreased in connection with the sale of the Vermont Yankee nuclear station in July 2002. Also contributing to the decrease was reduced ongoing payments resulting from the November 2002 buyout of a purchased power contract.

Purchased power expense for the fiscal year ended March 31, 2002 decreased approximately $17 million compared with the same period in 2001. The decrease was caused primarily by the termination of the Company’s obligation to provide power to Narragansett Electric Company as described in Operating Revenue, above. The decrease is partially offset by increased costs attributed to a refueling outage at Vermont Yankee during the quarter ended June 30, 2001, the refund of excess nuclear insurance and tax credits to Maine Yankee and Connecticut Yankee during the quarter ended December 31, 2000 and the inclusion of Montaup’s purchased power costs throughout the fiscal year ended March, 2002 in comparison to eleven months in fiscal year 2001.

Operation and maintenance expense decreased approximately $1 million for the fiscal year ended March 31, 2003, compared with the same period in 2002. The decreased cost is primarily the result of the sale of Seabrook Nuclear Generating Station (Seabrook) in November 2002. The decrease was partially offset by increased costs from a refueling outage at Seabrook prior to the sale and increased transmission maintenance costs.

Operation and maintenance expense for the fiscal year ended March 31, 2002 decreased approximately $27 million compared with the same period in 2001 primarily as a result of the sale of Millstone 3. Offsetting the decrease was increased pension costs as compared with the same period in the prior year due primarily to the sale of Millstone 3.

Purchased power contract buyout and nuclear fuel amortization expense for the fiscal years ended March 31, 2003 and 2002 increased approximately $2 million and $6 million, respectively, as compared with the same periods in the previous fiscal years. The increases were due primarily to scheduled purchased power contract buyout cost increases based upon rate agreements. The increases were partially offset by decreased nuclear fuel amortization due to the sale of the Millstone plant in March 2001 and the Seabrook plant in November 2002.

Other depreciation and amortization expense for the fiscal year ended March 31, 2003, increased by approximately $7 million compared with the same period in 2002. The increase is due to the Company’s payment in November 2002 of approximately $5 million to the Seabrook decommissioning trust fund for its share of the balance needed to raise the fund to the level required in the plant sales agreement.

Other depreciation and amortization expense for the twelve months ended March 31, 2002 decreased approximately $48 million compared with the same period in 2001. This decrease is due to reduced nuclear depreciation and decommissioning expense as a result of the sale of Millstone 3 in March 2001, and the full recovery of the Company’s CTC-related fixed costs associated with its generating plants and regulatory assets (excluding Montaup’s fixed costs) at the end of 2000.

Other Income and Expense for the fiscal year ended March 31, 2003 was comparable with the same period in 2002. Other income for the twelve months ended March 31, 2002 increased approximately $13 million compared with the same period in 2001. The increase is due primarily to the cessation of goodwill amortization as a result of the adoption of FAS 142 and an increase in allowance for equity funds used during construction, partially offset by reduced earnings from the Yankees and decreased interest income from other investing activities.

Interest Expense for the fiscal year ended March 31, 2003, decreased approximately $6 million compared with the same periods in 2002, primarily due to decreased interest rates on the Company’s variable rate long-term debt. Interest expense for the fiscal year ended March 31, 2002 decreased approximately $7 million compared with the same period in 2001 primarily due to decreased interest rates on the Company’s variable-rate long-term debt and the refinancing of short-term debt.

At March 31, 2003 the Company’s principal sources of liquidity included cash and cash equivalents of approximately $248 million and accounts receivable of $137 million. The Company has a working capital balance of approximately $245 million.

Net cash flows provided by operating activities for the fiscal year ended March 31, 2003, was approximately $102 million. The Company made a payment of approximately $77 million in November 2002 under a 1997 purchased power transfer agreement with USGen, the purchaser of its generation assets. The payment formally releases the Company as the obligor from one of the power purchase agreements covered by the transfer agreement and reduces future payments under that agreement.

Net cash flows provided by investing activities for the fiscal year ended March 31, 2003, increased approximately $61 million compared with same period in 2002, primarily due to a one-time cash inflow of the proceeds from the sale of Seabrook in November 2002.

At March 31, 2003 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 March 31, 2003 the Company had lines of credit and standby bond purchase facilities with banks totaling $419 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 March 31, 2003. 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 $42 million for the fiscal year ended March 31, 2003 and were primarily transmission-related. The funds necessary for utility plant expenditures during the period were primarily provided by internal funds.

All of the Company’s construction expenditures during the fiscal years ended March 2004 through March 2006 is expected to be financed by internally generated funds. The Company’s capital obligations consist of amounts for purchased power, long-term debt maturities and operating leases. The purchased power commitments are other than those reflected in the liabilities section of the balance sheet. Payments by fiscal year are as follows:

In connection with the sale of Vermont Yankee the Company has entered into a power contract to buy 22.5 percent of the entitlement of the Vermont Yankee generation until 2012. At the same time the Company has entered into 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.

New Accounting Standards: In June 2001, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). FAS 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. For further information regarding FAS 143 see “Item 8, Financial Statements and Supplementary Data.”

In May 2003 the FASB issued Statement of Financial Accounting Standards No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (FAS 150). The Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. For further information regarding FAS 150 see Item 8. Financial Statements and Supplementary Data.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 March 31, 2003, 2002 and 2001, 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 year ended March 31, 2003, was approximately 1.52 percent.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A. FINANCIAL STATEMENTS

To the Stockholders and Board of Directors of

New England Power Company:

In our opinion, the accompanying balance sheets and the related statements of income, of comprehensive income, of retained earnings, and of cash flows present fairly, in all material respects, the financial position of New England Power Company at March 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended March 31, 2003 in conformity with accounting principles generally accepted in the United States of America. 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 of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.





/s/ PricewaterhouseCoopers LLP  
PricewaterhouseCoopers LLP


Boston, Massachusetts
May 7, 2003, except for the
Decommissioning Nuclear Units and
Town of Norwood Dispute sections of
Note D, as to which the dates are June 5, 2003
and June 25, 2003, respectively

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

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

---

New England Power Company
Balance Sheets

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

---

New England Power Company
Balance Sheets

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

---

New England Power Company
Statements of Cash Flows

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

---

New England Power Company
Statements of Cash Flows – (continued)

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

NOTE A - SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation: New England Power Company (the Company), a wholly owned subsidiary of National Grid USA, is a Massachusetts corporation qualified to do business in Massachusetts, New Hampshire, Connecticut, Rhode Island, Maine, and Vermont. The Company is subject, for certain purposes, to the jurisdiction of the regulatory commissions of these states (except Connecticut), the Securities and Exchange Commission (SEC), under the Public Utility Holding Company Act of 1935 (1935 Act), the Federal Energy Regulatory Commission (FERC), and the Nuclear Regulatory Commission (NRC). The Company’s accounting policies conform to Generally Accepted Accounting Principles (GAAP), including the accounting principles for rate-regulated entities and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities.

Nature of Operations: The Company's business is primarily the transmission of electric energy in wholesale quantities to other electric utilities, principally its distribution affiliates Granite State Electric Company, Massachusetts Electric Company, Nantucket Electric Company, and The Narragansett Electric Company. The Company’s transmission facilities are part of National Grid USA’s transmission operations, which are represented under the name National Grid Transmission USA. In addition, the Company owns a minority interest in one fossil fuel generating unit and sold a minority interest in one jointly owned nuclear generating unit in November 2002. The Company also owns minority equity interests in four nuclear generating companies (Yankees), three of which own generating facilities that are permanently retired and are conducting decommissioning operations and the fourth of which sold its generating assets in July 2002.

Goodwill: The Company’s goodwill is primarily the result of two mergers that were accounted for by the purchase method: the merger of New England Electric System and National Grid Transco plc (formerly National Grid Group plc) on March 22, 2002 and the acquisition of Eastern Utilities Associates by National Grid USA (a wholly owned subsidiary of National Grid Transco plc) on April 19, 2000. The approximately $2.1 billion of goodwill that resulted from the transactions was pushed down and reflected on the financial statements of the National Grid USA subsidiaries, including $356 million allocated to the Company.

The Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets” (FAS 142) effective April 1, 2001. In accordance with FAS 142, goodwill can no longer be amortized and must be reviewed for impairment at least annually. In the fiscal year ended March 31, 2001, the final year that the Company amortized goodwill, the effect to net income was approximately $18 million.

The Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the performance of the annual goodwill impairment test. The result of the annual analysis determined that no adjustment to the goodwill carrying value was required.

Use of Estimates: In preparing the financial statements, management is required to make estimates that affect the reported amounts of assets and liabilities and disclosures of asset recovery and contingent liabilities as of the date of the balance sheets, and revenues and expenses during the reporting period. Actual results could differ from those estimates.

Utility Plant: The cost of additions to utility plant and replacements of retirement units of property are capitalized. Costs include direct material, labor, overhead and AFDC. Replacement of minor items of utility plant and the cost of current repairs and maintenance are charged to expense. Whenever utility plant is retired, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation.

Allowance for Funds Used During Construction (AFDC): The Company capitalizes AFDC as part of construction costs. AFDC represents an allowance for the cost of funds used to finance construction. AFDC is capitalized in "Utility plant" with offsetting noncash credits to "Other income" and "Interest”. This method is in accordance with an established rate-making practice under which a utility is permitted a return on, and the recovery of, prudently incurred capital costs through their ultimate inclusion in rate base and in the provision for depreciation. The composite AFDC rates were 7.7 percent, 8.1 percent and 3.2 percent for the years ended March 31, 2003, 2002, and 2001, respectively.

Depreciation and Amortization: The depreciation and amortization expense included in the statements of income is composed of the following:

Depreciation is provided annually on a straight-line basis. The provision for depreciation as a percentage of weighted average depreciable transmission property was 2.3 percent for all periods presented. Amortization of purchase power contracts and regulatory assets covered by contract termination charges (CTC) are in accordance with rate settlement agreements.

Federal and State Income Taxes: Income taxes have been computed utilizing the asset and liability approach that requires the recognition of deferred tax assets and liabilities for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities (see Note G).

Cash and Cash Equivalents: The Company classifies short-term investments with a maturity at purchase date of 90 days or less as cash equivalents.

Comprehensive Income (Loss): Comprehensive income consists of net income and other gains and losses affecting common equity that, under generally accepted accounting principles are excluded from net income. For the Company, the components of accumulated other comprehensive income/(loss) consist of unrealized gains and losses on marketable equity investments. For the fiscal years ended March 31, 2003, 2002, and 2001 tax expense/(benefit) related to comprehensive income were approximately $78,000, $22,000 and ($94,000), respectively.

New Accounting Standards: In June 2001, the FASB SFAS No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). FAS 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. FAS 143 is effective for fiscal years beginning after June 15, 2002. The Company has evaluated the impact of this standard on its financial position and results of operations. Based on this evaluation the Company does not believe it has any asset retirement obligations that would have a material effect on its results of operations, cash flows and financial position.

In May 2003 the FASB issued Statement of Financial Accounting Standards No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (FAS 150). The Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. FAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company is currently evaluating the impact of FAS 150 on its financial position and results of operations.

Reclassifications: Certain amounts from prior years have been reclassified in the accompanying financial statements to conform with the 2003 presentation.

NOTE B – RATE AND REGULATORY ISSUES AND ACCOUNTING IMPLICATIONS

Because electric utility 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. In 1997, the Emerging Issues Task Force of the FASB concluded that a utility that had received approval to recover stranded costs through regulated rates would be permitted to continue to apply FAS 71 to the recovery of stranded costs.

The Company has received authorization from the FERC to recover through CTCs substantially all of the costs associated with its former generating business not recovered through the divestiture. Additionally, FERC Order No. 888 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 and related contractual commitments that were not recovered through the sale of those investments (stranded costs). These costs are recovered from the Company’s wholesale customers with whom it has settlement agreements through CTC which the affiliated wholesale customers recover through delivery charges to distribution customers. The recovery of the Company’s stranded costs is divided into several categories. The Company’s unrecovered costs associated with generating plants (nuclear and nonnuclear) and most regulatory assets will be fully recovered through the CTC by the end of 2009 and earn a return on equity (ROE) averaging 9.7 percent. The Company’s 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. As the CTC rate declines, the Company, under certain of the settlement agreements, earns incentives based on successful mitigation of its stranded costs. These incentives supplement the Company’s ROE.

In conjunction with the divestiture, the Company transferred to the buyer of its nonnuclear generating business (the buyer) its entitlement to power procured under several long-term contracts in exchange for monthly fixed payments by the Company. These fixed monthly payments by the Company, inclusive of Montaup’s share, average approximately $9 million per month through December 2009 toward the above-market cost of those contracts. 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 rate payers. At March 31, 2003 and 2002, the net present value is approximately $507 million and $659 million, respectively.

Under a 1997 purchased power transfer agreement, USGen New England, Inc. ("USGen") purchased from the Company an entitlement to approximately 1,100 megawatts of power procured under long-term contracts. In connection with this transfer agreement, the Company agreed to pay USGen a fixed amount for the above-market cost of the purchased power. The present value of this obligation is approximately $0.4 billion at March 31, 2003 and is recorded as a liability on the balance sheet, offset in full by a regulatory asset. In the event that USGen, which has recently encountered financial difficulty, defaults on the payments of these contracts the Company would assume the obligation, in turn, eliminating the fixed obligation to USGen. In that instance the Company would remove the $0.4 billion liability from its balance sheet and the corresponding regulatory asset. The Company believes that the impact on results of operations would not be material as the above-market portion of the contracts would continue to be passed to customers through CTCs. As indicated in Management's Discussion and Analysis of Financial Condition and Results of Operations, the Company made a $77 million payment in November 2002 to assign and permanently release the Company from future obligations under one purchased power agreement with USGen. The $77 million payment is recoverable from customers through CTCs.

As a result of applying FAS 71, the Company has recorded a regulatory asset for the costs that are recoverable from customers through the CTC. At March 31, 2003 and 2002 this amounted to approximately $1.3 billion and $1.4 billion, respectively, including $0.8 billion and $1.0 billion, respectively, related to the above-market costs of purchased power contracts, $0.3 billion and $0.2 billion, respectively, related to accrued Yankee nuclear plant costs, and $0.2 billion and $0.2 billion, respectively, related to other net CTC regulatory assets.

Pension: The Company has recognized an additional minimum pension liability of $94 million on its balance sheet in other reserves and deferred credits to reflect its under funded pension obligation.  Due to the nature of its rate plan the Company has recorded a regulatory asset representing the future collection of the liability from rate payers.

NOTE C – ACCOUNTING FOR NUCLEAR INVESTMENTS

Yankee Nuclear Power Companies: The Company has minority interests in four generating nuclear companies (the Yankees). These ownership interests are accounted for on the equity method. Three of the Yankees own nuclear generating units that have been permanently retired and are conducting decommissioning operations and one sold its nuclear generating unit in July 2002. The Company has power contracts with each of the decommissioning Yankees that require the Company to pay an amount equal to its share of total fixed and operating costs of the plant plus a return on equity. The Company’s share of the expenses of the Yankees is accounted for in “Purchased electric energy” on the income statement.

The following table summarizes financial information furnished by the Yankees:

At March 31, 2003, approximately $6 million of undistributed earnings of the nuclear power companies were included in the Company’s retained earnings.

Seabrook 1 Nuclear Generating Unit: The Company sold its 10 percent non-operating ownership interest in the Seabrook 1 Nuclear Generating Unit (Seabrook) in November 2002. Prior to the sale of Seabrook the Company’s share of expenses for the unit were accounted for in “Other operation” and “Maintenance” expenses on the income statement.

NOTE D – COMMITMENTS AND CONTINGENCIES

Decommissioning Nuclear Units: Three of the Yankees in which the Company has a minority interest 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 electric energy" on the income statement.

Future estimated billings are decommissioning cost estimates. These estimates include the projected costs of decontaminating the units as required by the Nuclear Regulatory Commission, dismantling the units, spent fuel storage, security, and liability and property insurance, as well as other costs. Such costs reflect estimates of total decommissioning costs which are recovered in rates regulated by the FERC. The decommissioning costs that are actually incurred by the Yankees may exceed the estimated amounts, perhaps substantially. For example, in light of new regulatory requirements security costs have already increased beyond previous estimates. Also, cost estimates assume the availability of permanent repositories for both low-level and high-level nuclear waste by 2023. Additionally costs may increase if the Yankees must replace decommissioning operations contractors who fail to perform in accordance with their obligations (see Bechtel Dispute below). In the third quarter of fiscal 2003 the Yankees increased their aggregate decommissioning estimates to reflect, projected future security, insurance cost increases and other expenses. Based on those estimates the Company's share of the additional cost is approximately $121 million. Under settlement agreements, the Company is permitted to recover prudently incurred decommissioning costs through CTCs.

Decommissioning Collections: Each of the Yankees has established a decommissioning trust fund, or escrow fund, into which its owners make payments to meet the projected costs of decommissioning. Under its power contract with each Yankee, the Company is liable for its pro rata share of their decommissioning costs. In addition, a Maine statute provides that if both Maine Yankee and its decommissioning trust fund have insufficient assets to pay to decommission the plant, the owners of Maine Yankee are jointly and severally liable for the shortfall. The Company has been paying and recording its portion of projected decommissioning costs for the plants owned by the Yankees consistent with its rate recovery. Maine Yankee and Connecticut Yankee are required to make filings with the FERC regarding their costs within the next 14 months. Yankee Atomic filed for a rate increase which the FERC allowed to become effective June 5, 2003, subject to refund. Subsequently Yankee Atomic has resumed making decommissioning collections.

DOE Dispute: The Nuclear Waste Policy Act of 1982 establishes that the federal government (through the 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 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. The court held that the DOE is liable for such failure in October 1998. The Yankees have filed a further action against the DOE to determine the level of damages. That action is pending. As an interim measure until the DOE meets its contractual obligations to dispose of the spent fuel, the Yankees have proceeded with construction of independent spent fuel storage installations ("ISFSIs") located at the plant sites. Yankee Atomic and Maine Yankee have commenced moving their spent nuclear fuel to their respective ISFSIs. Connecticut Yankee has not yet begun the process of moving spent nuclear fuel. The Yankees expect to complete the process of moving spent nuclear fuel to their respective ISFSIs by December 2004.

Bechtel Dispute: Connecticut Yankee has notified Bechtel Power Corporation, its decommissioning operations contractor, that it is in default of its obligations and that Connecticut Yankee intends to terminate its contract, subject to Bechtel’s right to cure. Bechtel has filed a proceeding in Connecticut Superior Court against Connecticut Yankee alleging breach of contract and other grounds. Connecticut Yankee intends to assert claims against Bechtel and to litigate its claims and defend against Bechtel's claims vigorously. These developments may delay the progress of decommissioning the Connecticut Yankee power plant and may increase the Company’s costs associated with it.

Divested Nuclear Units: Seabrook: The Company previously held a 10 percent non-operating ownership interest in the Seabrook Nuclear Generating Station (Seabrook). As part of a consortium of joint owners, the Company sold its interest in Seabrook to FPL Energy Seabrook LLC (FPL) on November 1, 2002. Pursuant to the transaction, FPL assumed the decommissioning liability and trust fund for the plant including the Company's share of both. Net of closing adjustments, the Company's share of the proceeds from the sale of Seabrook was approximately $84 million following its $5 million top-off payment to the decommissioning trust fund. Ninety-eight percent of the proceeds from the sale in excess of related expenses and the Company's post-1995 investment will be credited to the Company's customers through CTCs. The Company’s share of expenses for Seabrook prior to November 1, 2002 is accounted for in "Other operation" and "Maintenance" expenses on the income statement.

Vermont Yankee Nuclear Power Corporation: The Company has a 23.9 percent equity investment in the Vermont Yankee Nuclear Power Corporation (Vermont Yankee). Vermont Yankee was formerly the owner of Vermont Yankee Nuclear Generating station. On July 30, 2002, Vermont Yankee completed the sale of Vermont Yankee Nuclear Generating Station to Entergy Vermont Yankee LLC (ENVY) for approximately $180 million. The Company’s portion of the sale price was approximately $43 million for its 23.9 percent ownership interest in Vermont Yankee. As part of the transaction, ENVY assumed the decommissioning liability for the plant. Vermont Yankee received regulatory approval from the SEC on May 13, 2003 to distribute the net proceeds from the sale of the plant. The proceeds will be distributed through a series of dividend payments and stock buybacks. The majority of the Company’s net proceeds from the sale will be credited to its customers through CTCs.

Plant Expenditures: The Company’s utility plant expenditures are estimated to be approximately $64 million for 2004. At March 31, 2003, substantial commitments had been made relative to future planned expenditures.

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 support agreements entered into at the time these facilities were constructed, the Company agreed to guarantee a portion of the project debt. At March 31, 2003, the Company had guaranteed approximately $18 million of project debt, including $3 million originally guaranteed by Montaup, with terms through 2015. The Company’s rights and obligations under its support agreements were transferred to the purchaser of its nonnuclear generation, but the Company retained Montaup’s rights and obligations under its support agreement. The Company remains an obligor under the support agreements for the portion of the rights it transferred until 2020. Costs associated with these support agreements are recoverable through the Company’s transmission rates.

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 remediation of 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: From 1983 until 1998, the Company was the wholesale power supplier for Norwood. In April 1998, Norwood began taking power from another supplier. Pursuant to a tariff amendment approved by the Federal Energy Regulatory Commission (FERC) in May 1998, the Company has been assessing Norwood a contract termination charge (CTC). Through March 31, 2003, the charges assessed Norwood amount to approximately $59 million, all of which remain unpaid. The Company filed a collection action in Massachusetts Superior Court (Superior Court). The Superior Court deferred action until the various appeals were decided. In March 2001, the Superior Court ordered Norwood to pay the Company approximately $27 million including interest, and affirmed Norwood’s obligation to make monthly CTC payments to the Company of approximately $600,000, plus interest. Norwood appealed the order in April 2001. Pending the appeal, Norwood entered into a consent order to establish a segregated account for the benefit of the Company in the amount of approximately $14 million and to make regular additions to the account. As of March 31, 2003, Norwood reported that the account has grown to approximately $23 million. Oral arguments on Norwood's appeal took place in March 2003 and a decision is expected soon. On December 23, 2002, Norwood filed a complaint with the FERC, challenging the CTC on multiple grounds. In a draft order released on or about June 25, 2003, FERC granted NEP's motion to dismiss those portions of Norwood's complaint under Section 206 of the Federal Power Act that Norwood previously litigated before FERC and the federal district court, and set down for hearing Norwood's challenge to the factors that are used to calculate the CTC rate. In so doing, the FERC set a refund effective date of February 21, 2003 and referred the matter initially to a FERC settlement judge, consistent with its normal procedures. The draft order is subject to further modification by FERC before it is issued in final form. For further information regarding the Town of Norwood dispute see Item 3, Legal Proceedings.

Millstone Unit 3: In November 1999, the Company entered into an agreement with NU to settle certain claims. Among other things, the settlement agreement provided for NU to include the Company’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, the Company was to receive a fixed amount, regardless of the actual sale price. In March 2001, the Millstone units were sold, including the Company’s interest in Millstone 3, for $1.3 billion. In accordance with the settlement agreement, the Company was paid approximately $27.9 million, from which the Company 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 the Company would have received approximately $140 million of sale proceeds if there had been no agreement with NU. In the event that one or more of the states proceed with such a challenge, the dispute will be resolved by the FERC. The Company believes it has a strong argument that it acted prudently, as the amount it received under the settlement agreement was the highest sale price for a nuclear unit at the time the agreement was reached.

Contracts for the Purchase of Electric Power: The Company has contracts for the purchase of electric power. The Company’s commitments for future fiscal periods, under these long-term contracts as of March 31, 2003, is as follows (in thousands): 2004, $67 million; 2005, $56 million; 2006, $40 million; 2007, $42 million: and 2008 and thereafter $239 million.

In connection with the sale of Vermont Yankee, the Company entered into a power contract to buy 22.5 percent of the entitlement of the Vermont Yankee generation until 2012. At the same time the Company has entered into 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.

NOTE E - SEGMENTS

The Company's reportable segments are electric transmission and electric other. 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. General corporate expenses include the cost of the services furnished by National Grid USA Service Company, Inc., an affiliated service company operating pursuant to the provisions of Section 13 of the 1935 Act. Assets allocated to the electric transmission and electric other segments include net utility plant, materials and supplies, and certain regulatory and other assets. Corporate assets consist primarily of other property and investments, cash, restricted cash, and unamortized debt expense.

NOTE F - PENSION AND POSTRETIREMENT BENEFIT PLANS OTHER THAN PENSIONS

Pension Plan: The Company participates with certain other subsidiaries of National Grid USA in a noncontributory, defined benefit plan covering substantially all employees of the Company. The plan provides pension benefits based on the employee's compensation during the five years prior to retirement. Absent unusual circumstances, the Company’s funding policy is to contribute each year the net periodic pension cost for that year. However, the contribution for any year will not be less than the minimum contribution required by federal law or greater than the maximum tax-deductible amount.

Net pension cost for the years ended March 31, 2003, 2002 and 2001 included the following components:

The funded status of the plan cannot be presented separately for the Company as the Company participates in the plan with certain other National Grid USA subsidiaries (Massachusetts Electric Company, The Narragansett Electric Company, Granite State Electric Company, Nantucket Electric Company and National Grid USA Service Company, Inc.). The following provides a reconciliation of benefit obligations and plan assets for the National Grid USA companies’ plan at March 31:

Plan assets are composed primarily of equity and fixed income securities.

Additional Minimum Liability (AML): Statement of Financial Accounting Standards 87 “Employers’ Accounting for Pensions” states that if a pension plans '  accumulated benefit obligation  (ABO)  exceeds the fair value of plan assets, the employer shall recognize in the statement of financial position a liability that is at least equal to the unfunded  ABO with an offsetting charge to other comprehensive income. Due to the severe downturn in the capital markets the Company's ABO at March 31, 2003 is greater than the fair value of plan assets.  As such, the Company has recognized an additional minimum pension liability of $94 million on its balance sheet in other reserves and deferred credits reflecting the under funded pension obligation.  However, due to the nature of its rate plan the Company has not charged other comprehensive income but has instead recorded a regulatory asset.  If in the future, capital markets recover such that the fair value of plan assets is once again greater than the ABO, the additional minimum pension liability will be removed from the Company's balance sheets.

Postretirement Benefit Plans Other than Pensions (PBOPs): The Company provides health care and life insurance coverage to eligible retired employees. Eligibility is based on certain age and length of service requirements and in some cases retirees must contribute to the cost of their coverage.

The Company's total cost of PBOPs for the years ended March 31, 2003, 2002 and 2001 included the following components:

The following provides a reconciliation of benefit obligations and plan assets at March 31:

The assumptions used in the health care cost trends have a significant effect on the amounts reported. A one percentage point change in the assumed rates would increase the accumulated postretirement benefit obligation (APBO) as of March 31, 2003 by approximately $8 million or decrease the APBO by approximately $7 million, and increase or decrease the net periodic cost for 2004 by approximately $500,000.

The Company generally makes contributions to the plans equal to the annual allowable tax-deductible amount.

NOTE G – FEDERAL AND STATE INCOME TAXES

The Company and other subsidiaries participate with National Grid General Partnership, a wholly owned subsidiary of National Grid Transco plc, in filing consolidated federal income tax returns. The Company's income tax provision is calculated on a separate return basis. Federal income tax returns have been examined and all appeals and issues have been agreed upon by the Internal Revenue Service and the Company through 1996.

Total income taxes in the statements of income are as follows:

Total income taxes, as shown above, consist of the following components:

Since 1998, the Company has been amortizing previously deferred investment tax credits (ITC) related to generation investments over the CTC recovery period. Unamortized ITC related to generating units divested in 1998 and 2001 were credited to other income pursuant to federal tax law. Previously recognized ITC related to transmission facilities are amortized over their estimated productive lives.

Total income taxes, as shown above, consist of federal and state components as follows:

With regulatory approval from the FERC, the Company has adopted comprehensive interperiod tax allocation (normalization) for temporary book/tax differences.

Total income taxes differ from the amounts computed by applying the federal statutory tax rates to income before taxes. The reasons for the differences are as follows:

The Company adopted SFAS No. 109, “Accounting for Income Taxes”, which requires recognition of deferred income taxes for temporary differences that are reported in different years for financial reporting and tax purposes using the liability method. Under the liability method, deferred tax liabilities or assets are computed using the tax rates that will be in effect when temporary differences reverse. Generally, for regulated companies, the change in tax rates may not be immediately recognized in operating results because of rate-making treatment and provisions in the Tax Reform Act of 1986.

The following table identifies the major components of total deferred income taxes:

There were no valuation allowances for deferred tax assets deemed necessary at March 31, 2003, 2002 and 2001, respectively.

NOTE H - SHORT-TERM BORROWINGS

At March 31, 2003 and 2002 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 March 31, 2003 and 2002 the Company had lines of credit and standby bond purchase facilities with banks totaling $419 million and $456 respectively, which are 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 March 31, 2003. Fees are paid on the lines and facilities in lieu of compensating balances.

NOTE I - CUMULATIVE PREFERRED STOCK

A summary of cumulative preferred stock at March 31, 2003, 2002 and 2001, is as follows (in thousands of dollars except for share data):

(a) Noncallable.

The annual dividend requirement for cumulative preferred stock was approximately $82,000 and $86,000 for 2003 and 2002, respectively.

There are no mandatory redemption provisions on the Company’s cumulative preferred stock.

NOTE J – LONG-TERM DEBT

A summary of long-term debt is as follows:

(a) CDA = Connecticut Development Authority

(b) MIFA = Massachusetts Industrial Finance Authority
(c) BFA = Business Finance Authority of the State of New Hampshire

At March 31, 2003, interest rates on the Company's variable rate long-term bonds ranged from 1.1 percent to 1.45 percent. There are no payments or sinking fund requirements due in 2004 through 2007.

At March 31, 2003, the Company's long-term debt had a carrying value and fair value of approximately $410 million. The fair value of debt that re-prices frequently at market rates approximates carrying value.

NOTE K - SUPPLEMENTARY INCOME STATEMENT INFORMATION

Advertising expenses, expenditures for research and development, and rents were not material and there were no royalties paid in the years ended March 31, 2003, 2002 or 2001. Taxes, other than income taxes, charged to operating expenses are set forth by class as follows:

Transactions between the Company and other affiliated companies for sales of electric energy and other sales amounted to approximately $324 million, $354 million and $386 million for the years ended March 31, 2003, 2002 and 2001, respectively.

National Grid USA Service Company, Inc., an affiliated service company operating pursuant to the provisions of Section 13 of the 1935 Act, furnished services to the Company at the cost of such services. These costs amounted to approximately $46 million, $43 million and $43 million including capitalized construction costs of $10 million, $15 million and $19 million for the years ended March 31, 2003, 2002 and 2001, respectively.

NOTE L – SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Per share data is not relevant because the Company's common stock is wholly owned by National Grid USA, a wholly owned subsidiary of National Grid Transco plc.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

The Company has nothing to report for this item.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following table lists the Company’s executive officers and directors:

Each member of the board of directors is elected at the annual meeting of stockholders and holds office until the next annual meeting or a special meeting in lieu thereof, and until his or successor is elected and qualified. There are no family relationships between any of the directors and the executive officers listed in the table.

Mr. Flynn served as President from January 1999 to April 2003 and was a member of the Company’s Board of Directors during that period. He has been a Vice President of National Grid USA since 2000 and served as Vice President and Director of Rates for National Grid USA Service Company from 1996 to 1999.

Mr. Lewis was elected President effective April 16, 2003; he was Vice President from February 26, 2003 until April 16. He has been a Vice President of National Grid USA since November 2002. He was elected President of National Grid Transmission Services Corporation in December 2002 and elected Vice President of Niagara Mohawk Power Corporation and National Grid USA Service Company, Inc. in November 2002. From 2001 to 2002, he was Manager of UK Electricity Services for National Grid. From 1997 to 2001, he was a Network Manager for Services for National Grid.

Mr. Cochrane was elected Chief Financial Officer effective August 1, 2002 and Vice President effective January 2002 and has served on the Company’s Board since 2002. He was the Company’s Treasurer from 1998 to January 31, 2002. He has served as National Grid USA’s Chief Financial Officer since January 2001 and Senior Vice President since May 2002 and was Treasurer of National Grid USA (and its predecessor, New England Electric System) and of National Grid USA Service Company from 1998 to 2002. Mr. Cochrane was also Treasurer of Massachusetts Electric Company from 1998 to 2000 and of The Narragansett Electric Company from 1993 to 2000.

Mr. Mahoney joined the Company as Vice President in May 2000 at the merger of Montaup Electric Company with the Company. Prior to that he was Vice President, Field Operations, of Eastern Utilities Associates from 1997 to 2000.

Mr. Reilly joined the Company’s Board of Directors in 2001 and has been a Vice President of the Company and Secretary and General Counsel of National Grid USA since January 2001. Since 2000 he has been National Grid USA Senior Vice President, and he served as President of Massachusetts Electric Company, The Narragansett Electric Company, Nantucket Electric Company and Granite State Electric Company from 1996 to 2000.

Mr. Robinson has been the Company’s Treasurer since January 31, 2002 and has served as Vice President since 1998. He was the Company’s Director of Nuclear Investments from 1997 to 1998.

Ms. Rosenqvist was elected Vice President in 1998. Prior to that, she served as Manager of Transmission Tariffs and Contracts for NEP and National Grid USA Service Company.

Mr. Schrayshuen has been Vice President since January 31, 2002. He was Director of Electric Assets from 1999 to 2002 and Director of Energy Transactions from 1998 to 1999.

Mr. Capomacchio has served as Controller of the Company and of Massachusetts Electric Company, The Narragansett Electric Company, Nantucket Electric Company and Granite State Electric Company since May 2001. Since January 2002, he has served as Vice President and Controller of National Grid USA Service Company and as Controller of Niagara Mohawk Power Corporation. Mr. Capomacchio was Assistant Controller of National Grid USA Service Company from 1998 to 2002.

Mr. Jesanis was elected director in 2000. He has served as National Grid USA’s Executive Vice President and Chief Operating Officer since January 31, 2001. He served as Senior Vice President and Chief Financial Officer of National Grid USA’s predecessor, New England Electric System, from 1998 to 2000 and was its Treasurer from 1992 to 1998. Mr. Jesanis is also a director of National Grid USA and of Niagara Mohawk Power Corporation.

Mr. Winser was elected director April 16, 2003. He joined the board of National Grid Transco in April 2003 as executive director responsible for UK and US transmission operations. He was appointed Senior Vice President of National Grid USA in January 2002 and was appointed to National Grid USA’s Board of Directors in April 2003. He joined The National Grid Company in 1993, becoming Director of Engineering in 2001.

Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s executive officers and directors, and persons who own more than 10 percent of a registered class of the Company’s equity securities, to file reports with the Securities and Exchange Commission disclosing their ownership of stock in the Company and changes in such ownership. To the Company’s knowledge, based solely on written representations from reporting persons, no such reports were required to be filed during the fiscal year ended March 31, 2003.

Summary Compensation Table

The following table sets forth the compensation paid or accrued for services rendered to NEP in fiscal years 2003, 2002 and 2001 by the president and the two most highly paid persons who were serving as executive officers on March 31, 2003 (the Named Executive Officers).

Option Grants in Last Fiscal Year

The following table shows all stock option grants to the Named Executive Officers during fiscal year 2003.

The options vest over time, subject to a performance condition. The options are exercisable only if and to the extent that National Grid’s total shareholder return (as defined in the applicable plan) during the three years of the performance period is equal to or better than the median of a specific comparison group. If the performance condition is not met after the three-year period, the National Grid Transco Remuneration Committee may modify the performance condition or methodology on subsequent anniversaries of the performance period, taking into account any factor it deems relevant.

Option Exercises in Fiscal Year 2003 and Fiscal Year-End Option Values

The following table sets forth, for the Named Executive Officers, the number of shares for which stock options were exercised in fiscal year 2003, the realized value or spread (the difference between the exercise price and market value on the date of exercise) and the number and unrealized spread of the unexercised options held by each at fiscal year-end.

Pension Plans

The Named Executive Officers participate in the National Grid USA Companies Final Average Pay Pension Plan (FAPP). FAPP is a noncontributory, tax-qualified defined benefit plan which provides all employees of National Grid USA and its subsidiaries with a minimum retirement benefit. Pension benefits are related to compensation, subject to the maximum annual limits noted in the pension table below. Under FAPP, a participant’s retirement benefit is computed using formulas based on percentages of highest average compensation computed over five consecutive years. The compensation covered by the pension plan includes salary, bonus and incentive share awards.

The Executive Supplemental Retirement Plan (“ESRP”) is a noncontributory, nonqualified defined benefit plan that provides additional retirement benefits to the Named Executive Officers and certain members of management who are eligible to receive a FAPP benefit and whose compensation exceeds legal limits under the applicable plan or who are otherwise selected for participation. Depending on the participant, the ESRP may provide for unreduced benefits payable as early as age 55, may enhance the qualified plan formula, may give credit for more years of service or may award benefits not otherwise payable due to limits on benefits that can be provided under the qualified plan.

The following table shows the maximum retirement benefit (adjusted for Social Security, if applicable) an executive officer can earn in aggregate under FAPP together with the ESRP. The benefit calculations are made as of March 31, 2003 and assume the officer has selected a straight life annuity commencing at age 65. Annual compensation limits of $200,000 under a tax-qualified plan will reduce the portion payable for some highly compensated officers. The benefits listed are shown without any joint and survivor benefits. If at age 65 a participant elected a 100 percent joint and survivor benefit with a spouse of the same age, the benefit shown in the table would be reduced by approximately 16 percent.

For purposes of the pension program, the Named Executive Officers had approximately the following credited years of benefit service at March 31, 2003: Mr. Flynn, 21 years; Ms. Rosenquivst, 21 years; and Mr. Mahoney, 26 years.

At retirement, the Named Executive Officers may become eligible for post-retirement health and life insurance benefits determined based on their age and service. The executive may be required to contribute to the cost of benefits, depending on date of hire and total years of service.

Change-in-Control Payments

Under the National Grid USA companies’ executive compensation plan, in the event of a change in control, each Named Executive Officer would receive a cash payment in an amount equal to the average annual bonus percentage in the officer’s incentive compensation plan for the three prior years multiplied by that officer’s annualized base compensation. These payments would be made in lieu of the bonuses under these plans for the year in which the change in control occurs. In addition, provisions in the Retirees Health and Life Insurance Plan prevent changes in benefits adverse to the participants for three years following a change in control. Upon a change in control of National Grid USA, a participant in the deferred compensation plan may elect to receive a full distribution from the participant’s accounts plus the actuarial value of future benefits in relation to the insurance-related benefits under a prior plan, all less 10 percent.

The following table indicates the number of ordinary shares of National Grid Transco beneficially owned as of June 19, 2003 by: (a) each director of the Company; (b) each of the Named Executive Officers; and (c) all directors and executive officers of the Company as a group. Except as indicated, each such person has sole investment and voting power with respect to the shares shown as being beneficially owned by such person, based on information provided to the Company. Each person listed in this table owns less than one percent of the outstanding equity securities of National Grid Transco. National Grid USA owns all of the common stock of the Company.

None.

ITEM 14. CONTROLS AND PROCEDURES

The Company has established and maintains disclosure controls and procedures which are designed to provide reasonable assurance that material information relating to the Company, including its consolidated subsidiaries, is made known to management by others within those entities, particularly during the period in which this quarterly report is being prepared. The Company has established a Disclosure Committee, which is made up of several key management employees and which reports directly to the Chief Financial Officer and President. The Disclosure Committee monitors and evaluates these disclosure controls and procedures. The Chief Financial Officer and President have evaluated the effectiveness of the Company’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report. Based on this evaluation, it was determined that these disclosure controls and procedures were effective in providing reasonable assurance during the period covered in this annual report. There were no significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of the most recent evaluation.

ITEM 15. EXHIBITS AND REPORTS ON FORM 8-K

Reports on Form 8-K

The Company did not file any current reports on Form 8-K during the last quarter of fiscal year ended March 31, 2003.

Exhibits

The exhibit index is incorporated herein by reference.

Pursuant to the Requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on June 27, 2003 by the following persons on behalf of the registrant and in the capacities indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company.

Certification of Principal Executive Officer

I, Stephen P. Lewis, certify that:

1. I have reviewed this annual report on Form 10-K of New England Power Company (the “Report”);

2. Based on my knowledge, this Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Report;

3. Based on my knowledge, the financial statements, and other financial information included in this Report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this Report (the “Evaluation Date”); and

c) presented in this Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this Report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Certification of Principal Financial Officer

I, John G. Cochrane, certify that:

1. I have reviewed this annual report on Form 10-K of New England Power Company (the “Report”);

2. Based on my knowledge, this Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Report;

3. Based on my knowledge, the financial statements, and other financial information included in this Report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this Report (the “Evaluation Date”); and

c) presented in this Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this Report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.