UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


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

For the fiscal year ended March 31, 2005


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

For the transition period from to


Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address and Telephone Number	Identification Number

1-6564	New England Power Company (a Massachusetts corporation) 25 Research Drive Westborough, MA 01582 508-389-2000	04-1663070

Securities registered pursuant to Section 12(b) or Section 12(g) of the Act: None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES þ NO o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K þ

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). YES o NO þ

State the aggregate market value of the common equity held by nonaffiliates of the registrant: N/A

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

TABLE OF CONTENTS


		PAGE
	PART I

Item 1.	Business		4
Item 2.	Properties		6
Item 3.	Legal Proceedings		7
Item 4.	Submission of Matters to a Vote of Security Holders		7

	PART II

Item 5.	Market for the Registrant's Common Equity, Related Stockholders Matters and Issuer Purchases of Equity Securities		8
Item 6.	Selected Financial Data		8
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		9
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		15
Item 8.	Financial Statements and Supplementary Data		16
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		60
Item 9A.	Controls and Procedures		60
Item 9B.	Other Information		60

	PART III

Item 10.	Directors and Executive Officers of the Registrant		61
Item 11.	Executive Compensation		62
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		66
Item 13.	Certain Relationships and Related Transactions		67
Item 14.	Principal Accountant Fees and Services		67

	PART IV

Item 15.	Exhibits and Financial Statement Schedules		68
	Signatures		69

Explanatory Note: On June 20, 2005, management of New England Power Company concluded there were accounting errors for certain true-ups for revenues relating to regulatory filings for the recovery of stranded costs and certain true-ups for expenses relating to federal and state income tax filings in fiscal 2001, 2002, 2003 and 2004. In addition, some amounts recorded for revenue in fiscal 2004 were calculated incorrectly, and the corrections were recorded during the fiscal quarter ended December 31, 2004. Management’s investigation and review of the affected accounts resulted in the restatement of the financial statements.

This Form 10-K contains restated statements of income, comprehensive income, retained earnings, and cash flows for fiscal years ended March 31, 2003 and 2004 and restated balance sheet as of March 31, 2004. See Note N “Restatement of Previously Issued Financial Statements” in Item 8. Financial Statements and Supplementary Data.

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

	(a)		the impact of further electric utility industry restructuring;

	(b)		the impact of general economic changes;

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

	(d)		federal regulatory developments concerning regional transmission organizations;

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

	(f)		timing and adequacy of rate relief;

	(g)		adverse changes in electric load;

	(h)		acts of terrorism;

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

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

PART I

ITEM 1. BUSINESS

New England Power Company (the Company or NEP) is a wholly owned subsidiary of National Grid USA (formerly New England Electric System (NEES)) and, indirectly, National Grid Transco plc. NEP is a Massachusetts corporation qualified to do business in Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine and Vermont. NEP’s transmission facilities are part of National Grid USA’s transmission operations.

NEP’s business is primarily the transmission of electricity in wholesale quantities to other electric utilities, principally its New England electricity distribution affiliates: Massachusetts Electric Company, The Narragansett Electric Company, Granite State Electric Company and Nantucket Electric Company. The facilities of NEP, together with those of these affiliates, constitute an electricity transmission and distribution system that is directly interconnected with the facilities of its New York affiliate, Niagara Mohawk Power Corporation and other utilities in New England and New York State, and indirectly interconnected with those of utilities in Canada.

Capital stock: Holders of NEP’s common stock and 6% Cumulative Preferred Stock have general voting rights. National Grid USA owns all of the common stock of NEP, or 99.69% of the voting stock. Non-affiliates own NEP’s 6% Cumulative Preferred Stock, or 0.31% of the voting stock.

Investees: The Company holds minority interests in three companies (the Yankees) that own nuclear generating facilities that are permanently retired and are conducting decommissioning operations. The Company also owns minority interests in two companies that transmit hydro electricity from Canada. The Company owns voting stock of the following companies in the amounts indicated:


			% Voting
			Securities
	State of		Owned by
Name of Company	Organization	Type of Business	NEP
Connecticut Yankee Atomic Power Company (a)	CT	Ownership of Permanently Shutdown Nuclear Unit		19.5	%

Maine Yankee Atomic Power Company (a)	ME	Ownership of Permanently Shutdown Nuclear Unit		24.0	%

Yankee Atomic Electric Company (a)	MA	Ownership of Permanently Shutdown Nuclear Unit		34.5	%

New England Hydro Transmission Corporation	NH	Electricity Transmission		3.4	%

New England Hydro-Transmission Electric Co., Inc.	MA	Electricity Transmission		3.4	%

(a)

For detail on the Company’s ownership interests in the Yankees, see Note C “Nuclear Investments” in Item 8. Financial Statements and Supplementary Data.

Regulation: Numerous activities of the Company are subject to regulation by various federal agencies. Under the Public Utility Holding Company Act of 1935 (the 1935 Act), many transactions of the Company are subject to the jurisdiction of the Securities and Exchange Commission (SEC). Under the Federal Power Act, the Company is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) with respect to rates and accounting. In addition, the Nuclear Regulatory Commission (NRC) has broad jurisdiction over nuclear units and federal environmental agencies have broad jurisdiction over environmental matters. NEP is also subject, for certain purposes, to the jurisdiction of the utility commissions of Massachusetts, New Hampshire, Rhode Island, Maine and Vermont. For more information on regulation by the FERC, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note A “Accounting Policies” in Item 8. Financial Statements and Supplementary Data.

The Company is a Participating Transmission Owner (PTO) in New England’s Regional Transmission Organization (RTO) which commenced operations effective February 1, 2005. ISO New England, Inc. (ISO) has been authorized by FERC to exercise the operations and system planning functions required of RTOs and will be the independent regional transmission provider under the ISO Open Access Transmission Tariff (ISO-OATT). The ISO-OATT is designed to provide non-discriminatory open access transmission services over the transmission facilities of the PTOs and recover their revenue requirements.

New England RTO and Rate Filing: FERC issued two orders in 2004 and two in 2005 that approved the establishment of the RTO and resolved certain issues concerning the proposed return on equity for New England PTOs. Other return issues were set for hearing. A number of parties, including NEP, have filed appeals from one or more of those orders with the US Court of Appeals for the District of Columbia Circuit.

NEP’s currently allowed ROE for transmission assets is 10.25%. Effective on the RTO operations date of February 1, 2005, NEP’s transmission rates began to reflect a proposed base return on equity of 12.8%, subject to refund, plus the additional 0.5% incentive return on regional network service (RNS) rates that FERC approved in March 2004. Approximately 70% of the Company’s transmission costs are recovered through RNS rates. An additional 1.0% incentive adder is also applicable to new RNS transmission investment, subject to refund.

NEP and the other PTOs participated in FERC proceedings to determine outstanding ROE issues, including base return on equity (ROE) and the proposed 1% ROE incentive for new transmission investment. On May 27, 2005, the administrative law judge issued an initial decision which concluded that the base ROE should be 10.72% and that NEP and other PTOs are not entitled to the proposed 1% ROE incentive. All parties will have the opportunity to file a brief on exceptions in response to the judge’s initial decision. A final FERC order is expected by year end 2005.

Compliance with Environmental Requirements: The Company’s operations and facilities are subject to numerous federal, state and local laws and regulations relating to the environment including, among other things, requirements concerning air and water quality; wetlands and flood plains; storage, transportation and disposal of hazardous wastes and substances; storage tanks; and site remediation. The Company believes it is handling identified wastes and by-products in a manner consistent with applicable requirements. The environmental management systems for the Company’s distribution and transmission facilities are certified to the International Organization for Standardization (ISO) 14001 standard. Management believes it is probable that costs associated with environmental compliance will continue to be recovered through the ratemaking process. The Company’s compliance has no material effect on its

capital expenditures, earnings or competitive position.

The Company has implemented an environmental audit program to identify any potential areas of concern and aid in compliance with legal requirements. The Company is also currently conducting a program to investigate and remediate, as necessary to meet current environmental standards, certain properties which the Company has learned may be contaminated with industrial waste, as well as investigating identified industrial waste sites as to which it may be determined that the Company has contributed. The Company has also been advised that various federal, state or local agencies believe certain properties require investigation and has prioritized the sites based on available information in order to enhance the management of investigation and remediation, if necessary.

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, the Company signed a purchased power transfer agreement through which USGen purchased the Company’s entitlement to power procured under long-term contracts. Effective April 1, 2005, the Company has resumed performance and payment obligations under the contracts that were transferred to USGen, as described in Note B “Rate and Regulatory” in Item 8. Financial Statements and Supplementary Data.

Segments: The Company’s reportable segments are electricity transmission and stranded cost recoveries. The Company is engaged principally in the business of electricity transmission. For more information, see Note J “Segments” in Item 8. Financial Statements and Supplementary Data.

Employee Relations: The Company receives substantial support for its activities from the employees of National Grid USA Service Company, Inc. (Service Company), an affiliated company that provides administrative support to all National Grid USA companies in accordance with the 1935 Act. The Company also receives construction services from Service Company. The Company reimburses Service Company for the costs associated with those services. For a more detailed discussion of Service Company support for the Company, see Note A “Accounting Policies” in Item 8. Financial Statements and Supplementary Data. In addition, at March 31, 2005, the Company had seven employees, six of whom are members of a labor organization, the International Brotherhood of Electrical Workers.

ITEM 2. PROPERTIES

The Company’s integrated system consists of approximately 2,361 circuit miles of transmission lines, and approximately 125 substations. The properties of the Company also include an integrated system of transmission lines, substations and distribution facilities. The Company also holds a nine percent joint ownership interest in the Wyman 4 fossil fuel plant located in Yarmouth, Maine.

Hydro-Quebec Interconnection: Three affiliates of the Company were created to construct and operate transmission facilities to transmit power from Hydro-Quebec to New England. Under the financial and organizational agreements (the Support Agreements) entered into at the time these facilities were constructed, the Company agreed to guarantee a portion of the project debt. At March 31, 2005, the Company had guaranteed approximately $13 million of project debt, with terms through 2015. As a result of the termination of an assignment of certain obligations under the Support Agreements on April 1, 2004, the Company recorded a capital lease with an offsetting liability of $38 million. The Company remains an obligor under the Support Agreements for its portion of the project debt until 2020. See Note B “Rate and Regulatory” in Item 8. Financial Statements and Supplementary Data for a discussion of the termination and the recovery of costs associated with these Support Agreements.

The Company and its affiliates along with the ISO, Hydro Quebec TransEnergie (HQTE) and the other interconnection rights holders have negotiated a series of agreements formalizing the ISO’s operational and administrative responsibilities concerning the Hydro Quebec Interconnection facilities and integrating these facilities into the newly formed New England RTO. The agreements include a Transmission Operating Agreement and a Transmission Service Administrative Agreement, which the FERC made effective as of April 1, 2005, along with associated rate schedules under the ISO open access transmission tariff. An Asset Owners Agreement and an Interconnection Operators Agreement were filed with FERC in draft form on March 31, 2005, and final versions are expected to be executed and filed when the documents are available in both English and French. These agreements and OATT rate schedules do not materially affect the underlying Support Agreements.

ITEM 3. LEGAL PROCEEDINGS

Town of Norwood Dispute: From 1983 to 1998, NEP was the wholesale power supplier for the Town of Norwood. In April 1998, Norwood began taking power from another supplier, although its contract term with NEP ran to 2008. Pursuant to a tariff amendment approved by the FERC in May 1998, NEP has been assessing Norwood a Contract Termination Charge (CTC). Through March 31, 2005, the charges assessed Norwood but not paid amount to approximately $77.7 million. Norwood made a payment of approximately $20 million in July 2004. NEP and Norwood are engaged in litigation in state court and at the FERC, as follows.

State Collection Action. NEP filed a collection action in Massachusetts Superior Court (Worcester County) to collect the CTC, which Norwood has refused to pay, apart from the initial payment in 2004. 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. Following unsuccessful appeals by Norwood, the Superior Court entered judgment for NEP on June 9, 2004 in the amount of approximately $43.3 million, based on amounts owed through January 31, 2001. Norwood continues to contest the judgment in the Massachusetts Appeals Court.

FERC Section 206 Challenge. In December 2002, Norwood filed a challenge to the CTC rate with the FERC under Section 206 of the Federal Power Act. Under this Section, the FERC has the power to grant prospective relief only. In an order dated July 2, 2003, the FERC set down for hearing Norwood’s challenge to the factors used to calculate the CTC rate for Norwood and set a refund effective date of February 21, 2003, which empowers the FERC to direct NEP to adjust Norwood’s liability for unpaid charges billed after that date in the event that Norwood’s challenge is successful. On June 9, 2004, the FERC administrative law judge issued an initial decision recommending that FERC revise the CTC formula to reduce the CTC amount that was previously calculated under the formula which FERC accepted and approved in 1998. On July 9, 2004, NEP filed a brief objecting to this initial decision, arguing that no reduction is appropriate. Norwood and the FERC staff have also challenged the initial decision, arguing that the reduction is not enough. The challenges are now under consideration by FERC and the parties are awaiting a decision.

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

No matters were submitted to a vote of security holders during the last quarter of the fiscal year ended March 31, 2005. The Annual Meeting of Stockholders was held on April 20, 2005. By a vote of 3,619,896 shares out of 3,631,013 total shares voted, the following actions were taken:

	•		The number of directors was fixed at five.

	•		The following persons were elected as directors: John G. Cochrane, Michael E. Jesanis, Stephen P. Lewis, Lawrence J. Reilly and Jeffrey A. Scott.

	•		James S. Robinson was elected Treasurer and Gregory A. Hale was elected Clerk.

	•		PricewaterhouseCoopers LLP, an independent registered public accounting firm, was appointed the Company’s auditor for the fiscal year ending March 31, 2006.

PART II

The common stock of NEP is held solely by National Grid USA. There is no public trading market for the Company’s common stock. The Company sold no equity securities during the period covered by this Annual Report. The Company did not repurchase any shares of its 6% Cumulative Preferred Stock during the fourth quarter of fiscal 2005. 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 “Preferred Stock”.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected financial information for NEP for the fiscal years ended March 31, 2005, 2004, 2003, 2002 and 2001, respectively. This information has been derived from the financial statements of NEP and should be read together with them.

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.


	Year Ended March 31,
			2004		2003		2002		2001
(In millions)	2005		(Restated)*		(Restated)*		(Restated)*		(Restated)*

Operating revenue	$	458	$	464	$	518	$	562	$	655

Operating income	$	84	$	79	$	83	$	92	$	88

Net income	$	77	$	76	$	80	$	82	$	58
Income from continuing operations per average common share		**		**		**		**		**

Total assets	$	2,676	$	2,733	$	2,943	$	2,742	$	2,888

Long-term debt	$	410	$	410	$	410	$	410	$	410

Cumulative preferred stock	$	1	$	1	$	1	$	2	$	1

Dividends per common share		**		**		**		**		**

Amounts for the fiscal years ended March 31, 2004, 2003, 2002 and 2001 have been restated. See Note N “Restatement of Previously Issued Financial Statements” in Item 8. Financial and Supplementary Data.

All of NEP’s shares of common stock are owned by its parent company. Therefore, management considers dividend information and per share data not relevant.

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

RESTATEMENT OF FINANCIAL STATEMENTS

On June 20, 2005, the Company’s management concluded it had made certain errors that understated net income in fiscal years 2003 and 2004 and accordingly the Company’s financial statements have been restated in this Form 10-K. In addition, Management’s Discussion and Analysis has been updated to reflect the restatements. See Note N “Restatement of Previously Issued Financial Statements” in Item 8. Financial Statements and Supplementary Data.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to apply policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. Because of the inherent uncertainty in the nature of the matters where estimates are used, actual amounts could differ from estimated amounts. The following accounting policies represent those that management believes are particularly important to the financial statements and require the use of judgment in estimating matters that are inherently uncertain.

Regulatory Assets and Liabilities: Regulatory assets represent costs that have been deferred to future periods when it is probable that the regulator (being the FERC or other regulatory body having jurisdiction) will allow future recovery of those costs through rates. The Company bases its assessment of recovery by either specific recovery measures or historical precedents established by the regulatory body. Regulatory liabilities represent previous collections from customers to fund future expected costs or amounts received in rates that are expected to be refunded to customers in future periods. These regulatory assets and liabilities typically include purchased power obligations, purchased power contract buyouts, nuclear decommissioning costs and pension costs. The accounting for these regulatory assets and liabilities is in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation”.

The Company continually assesses whether the regulatory assets continue to meet the criteria for probability of future recovery. This assessment considers factors such as changes in the regulatory environment, recent rate orders to other regulated entities under the same jurisdiction, and the status of any pending or potential deregulation legislation. If future recovery of costs becomes no longer probable, the assets would be recognized as current-period expense.

Amortization of regulatory assets is provided over the recovery period as allowed in the related regulatory agreement. Amortization of stranded cost regulatory assets is included in the depreciation and amortization captions on the income statement. Amortization of the above market cost of purchased power contracts and nuclear decommissioning costs are included in the contract termination and nuclear unit shutdown charges caption on the income statement.

Benefit Plans: The Company maintains qualified and nonqualified pension plans. The Company also provides health care and life insurance benefits for its retired employees. The Company’s qualified pension plans are funded through outside trusts. See “Employee Relations” in Item 1. Business for a discussion of the Company’s employees.

In addition to the market returns, various other assumptions also affect the pension and other post-retirement benefit expense and measurement of their respective obligations. The following is a description of some of those assumptions:

	•		Assumed return on assets. The estimated rate of return for various passive asset classes is based both on analysis of historical rates of return and forward looking analysis of risk premiums and yields. Current market conditions, such as inflation and interest rates, are evaluated in connection with the setting of our long-term assumption. A small premium is added for active management of both equity and fixed income. The rates of return for each asset class are then weighted in accordance with a target asset allocation, and the resulting long-term return on assets rate is then applied to the market-related value of assets. For fiscal 2005, the Company used an 8.5% assumed return on assets for its pension plan and 7.63% assumed return on assets for its other post-retirement benefits plan.

	•		Discount rate. In determining the discount rate, the Company considers Moody’s Aa rates for corporate bonds and public utility bonds. In addition, the Company considers other measures of interest rates for high quality fixed income investments which match the duration of the liabilities. A rate is chosen within the range set by these measures. For fiscal 2005, the Company used a discount rate of 5.75% to measure its pension and post-retirement benefit plans.

	•		Medical trend assumptions. The health care cost trend rate is the assumed rate of increase in per-capita health care charges. For 2005, the health trend was set at 10% with the ultimate trend of 5% reached in 2010.

Goodwill: The Company applies the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (FAS 142). In accordance with FAS 142, goodwill must be reviewed for impairment at least annually and between annual reviews if events occur or circumstances arise indicating that the asset may be impaired. 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.

Tax Provision: The Company’s tax provisions, including both current and deferred components, are based on estimates, assumptions, calculations and interpretation of tax statutes for the current and future years in accordance with SFAS No. 109, “Accounting for Income Taxes”. 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 March 22, 2000.

Management regularly makes assessments of tax return outcomes relative to financial statement tax provisions and adjusts the tax provisions in the period when facts become final.

Accounting for Derivative Instruments: The Company accounts for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (FAS 133), and SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” as amended. Under

the provisions of FAS 133, all derivatives except those qualifying for the normal purchase/normal sale exception are recognized on the balance sheet at their fair value. Fair value is determined using current quoted market prices.

RESULTS OF OPERATIONS

EARNINGS

Net income for the year ended March 31, 2005 was not significantly different from the prior year. Affecting net income during the fiscal year was one time tax adjustments that resulted from settlement of tax audits, partially offset by interest costs associated with these settlements and reduced stranded cost recoveries.

Net income for the year ended March 31, 2004 decreased approximately $3 million compared with the prior year. The reduction was due primarily to decreased mitigation incentives and reduced return on CTCs compared with the prior year. Also contributing to the decrease was reduced equity income from nuclear generation due to the sale of Vermont Yankee Nuclear Power Corporation (Vermont Yankee) in July 2002. These decreases were partially offset by increased transmission earnings during the year ended March 31, 2004 as compared to the same periods in 2003.

REVENUES

The Company has two primary sources of revenue: transmission and stranded cost recoveries. Transmission revenues are based on a formula rate that recovers the Company’s actual costs plus a return on investment. Stranded cost recovery revenues are collected through a Contract Termination Charge (CTC), which is billed to former wholesale customers of the Company in connection with the Company’s divestiture of its electricity generation investments. During the fiscal year ended March 31, 2003, the Company also had revenues associated with its ownership interests in the Vermont Yankee Nuclear Generating Station (Vermont Yankee) and the Seabrook Nuclear Generating Station (Seabrook). Vermont Yankee and Seabrook were sold in July 2002 and November 2002, respectively.

Operating revenue for fiscal year ended March 31, 2005 decreased approximately $6 million compared to the prior year. The decrease was due primarily to lower revenues resulting from decreased transmission operations and maintenance expenses and decreased benefit costs billed to transmission customers, partially offset by higher CTC revenues that resulted from recovery of expenses associated with the Hydro Quebec transmission line agreements (HQ Contracts). See Note B “Rate and Regulatory” in Item 8. Financial Statements and Supplementary Data for further discussion on the HQ Contracts.

Operating revenue for fiscal year ended March 31, 2004 decreased approximately $54 million compared to the prior year. The primary reason for the decrease was reduced sales of power received from Vermont Yankee and Seabrook during the fiscal 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. In addition, reduced mitigation incentives under the CTC contributed to the reduction in operating revenue.

OPERATING EXPENSES

Purchased electric energy for the fiscal year ended March 31, 2005 increased approximately $2 million

compared with the same period in 2004 primarily due to increased nuclear decommissioning costs in 2005 compared with the prior year partially offset by reductions in other purchased power expense.

Purchased electric energy for the fiscal year ended March 31, 2004 decreased approximately $33 million compared with the same period in 2003. The decrease was caused by reduced ongoing payments for purchased power due primarily to the buyout of a purchased power contract in November 2002. Also contributing to the decrease was the sale of Vermont Yankee in July 2002. Partially offsetting the decreases was the resumption of decommissioning billings by Yankee Atomic in June 2003.

Operation and maintenance expense for the fiscal year ended March 31, 2005 decreased approximately $2 million compared with the same period in 2004. This decrease was due primarily to a reduction in transmission operations and maintenance costs and employee benefit charges, offset by the resumption of support payments under the HQ contracts.

Operation and maintenance expense for the fiscal year ended March 31, 2004 decreased approximately $3 million compared with the prior year. The reduction was due primarily to the inclusion of expenses from Seabrook during the fiscal year ended March 31, 2003. Seabrook was sold in November 2002. Partially offsetting the decreased expense for the fiscal year ended March 31, 2004 were increased costs due to a voluntary early retirement program provided to employees which is discussed in Note H “Employee Benefits” in Item 8. Financial Statements and Supplementary Data.

Amortization of stranded costs for the fiscal year ended March 31, 2005 decreased approximately $3 million compared with the same period in 2004. The decrease was a result of the scheduled changes in amortization in accordance with the annual CTC filings.

Amortization of stranded costs for the fiscal year ended March 31, 2004 decreased approximately $2 million compared with the prior year. The decrease was a result of the scheduled changes in amortization in accordance with the annual CTC filings along with impacts associated with not recognizing a full year of amortization of regulatory liabilities that were established in connection with the sale of Seabrook and Vermont Yankee.

Other depreciation and amortization expense for the fiscal year ended March 31, 2005 increased approximately $1 million compared with the prior year due to an increase in plant expenditures.

Other depreciation and amortization expense for the fiscal year ended March 31, 2004 decreased approximately $7 million compared with the prior year. The decrease was due primarily to reduced decommissioning expenses as a result of the sale of Seabrook in November 2002.

Other taxes decreased approximately $1 million and $2 million for the years ended March 31, 2005 and 2004, respectively, compared with prior years primarily due to reductions in property taxes.

Income taxes decreased approximately $10 million for the year ended March 31, 2005 compared with the prior year. This decrease was a result of a $6 million reduction in tax expense from prior year tax return true-ups and settlements of tax audits in addition to a decrease in taxable income. Income taxes decreased approximately $2 million for the year ended March 31, 2004 compared with fiscal 2003 primarily due to lower taxable income.

Equity in income of nuclear power companies remained relatively unchanged during the fiscal year ended March 31, 2005 compared with the same period in the prior year. It decreased approximately $3

million during the fiscal year ended March 31, 2004 compared with the same period in fiscal 2003 due to the redemption of the Company’s interest in the Vermont Yankee Nuclear Power Corporation.

Other income net remained relatively unchanged during the fiscal year ended March 31, 2005 compared with the prior year. It increased approximately $2 million during the fiscal year ended March 31, 2004 compared with fiscal 2003 due to increased interest income and the sale of nonutility property.

Interest expense increased approximately $5 million for the fiscal year ended March 31, 2005 compared with the prior year primarily due to increased interest rates on the Company’s variable rate long-term debt and interest charges that resulted from a tax appeal settlement.

Interest expense decreased approximately $2 million for the fiscal year ended March 31, 2004 compared with the prior year primarily due to decreased interest rates on the Company’s variable rate long-term debt.

LIQUIDITY AND CAPITAL RESOURCES

At March 31, 2005 the Company’s principal sources of liquidity included cash and cash equivalents of approximately $311 million and accounts receivable of approximately $149 million. The Company has a working capital balance of approximately $375 million.

Net cash flows provided by operating activities increased approximately $76 million for the year ended March 31, 2005 compared with the same period in 2004. Cash improved from operating results due to the collection of a receivable in the amount of $20 million from the Town of Norwood in fiscal year 2005 and a purchased power buyout of $13 million in fiscal year 2004. In addition, the change in other current liabilities of $47 million was primarily a result of a reduction in income taxes paid of $53 million in fiscal year 2005 compared with fiscal year 2004, offset by a decrease in accrued taxes of $7 million.

Net cash flows used in investing activities for the fiscal year ended March 31, 2005 and 2004 were approximately $79 million and $25 million, respectively. Cash expenditures for these periods were primarily transmission utility plant expenditures. The funds necessary for utility plant expenditures during the period were primarily provided by internal funds.

Net cash flows used in financing activities for the fiscal year ended March 31, 2005 was approximately $236,000. Cash expenditures for the period were due primarily to dividends paid on preferred stock and preferred stock retirements.

At March 31, 2005 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, 2005, the Company had credit and standby bond purchase facilities with banks totaling $440 million which are available to provide liquidity support for $410 million of the Company’s long-term bonds and for other corporate purposes. There were no borrowings under these facilities at March 31, 2005. Fees are paid on the facilities in lieu of compensating balances.

Contractual Obligations: The Company’s capital obligations consist of amounts for purchased power, long-term debt maturities, construction expenditures and operating leases. Payments by fiscal year are as follows:


	Contractual Obligations due in:
			Less						More
			than 1						than 5
(In millions)	Total		year		1-3 years		3-5 years		years

Long term debt maturities	$	410	$	—	$	—	$	—	$	410
Interest on long term debt*		72		11		27		34		—
Purchased power commitments*		1,052		153		296		224		379
Construction expenditures**		91		91		**		**		**
Operating leases		1		1		—		—		—

Total	$	1,626	$	256	$	323	$	258	$	789

*	Forecasted, actual amounts could differ based on changes in market conditions.

**	Budgeted amount in which substantial commitments have been made. Amounts beyond 1 year are budgetary in nature and no contractual obligations have been made and therefore these amounts are not included.

Expected contributions to the Company’s pension and post-retirement benefit plans trusts (as disclosed in Item 8. Financial Statements and Supplementary Data - Note H. “Employee Benefits”) are not included on the above table.

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 electric generation until 2012. At the same time the Company entered into a contract with a third party to sell the entire 22.5 percent of the Vermont Yankee electric generation and effectively offset its purchased power contract costs. Since the Company does not take title to the electricity, the Company matches the cost of the power contract with the revenue from the sale of the power to the third party on its income statement and does not recognize any financial impact from the agreements on its financial statements.

Cost of Removal: The Company estimates it has collected over time approximately $20 million and $19 million for cost of removal through March 31, 2005 and 2004, respectively. For more information about the cost of removal see Note L “Cost of Removal” in Item 8. Financial Statements and Supplementary Data.

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

Paragraph 40 of the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standard (SFAS) No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” requires that presently enacted changes in laws impacting employer-sponsored retiree health care programs which take effect in future periods be considered in current-period measurements for benefits expected to be provided in those future periods. Therefore, under FAS 106 guidance, measures of plan liabilities and annual expense on or after the date of enactment should reflect the effects of this Act. Pursuant to guidance from the FASB under FSP FAS 106-2, the retiree health obligations will reflect the estimated subsidy payments expected from the federal government for the participant groups anticipated to qualify for the subsidy. Participant groups who are not expected to qualify, or have not yet been determined whether they will qualify, for the federal subsidy will not impact the retiree health obligations. If any portion of this group is subsequently determined to qualify for the subsidy, the retiree health care obligations will be adjusted at the time of that determination. The Company has chosen to apply the guidance prospectively, impacting retiree health costs. The Company adopted the provisions of FAS 106-2 on July 1, 2004. Reduced expense resulting from the Act of approximately $1 million was credited to customers. See Note H “Employee Benefits” in Item 8. Financial Statements and Supplementary Data.

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). FIN 47 will result in (a) more consistent recognition of liabilities relating to asset retirement obligations, (b) more information about expected future cash outflows associated with those obligations and (c) more information about investments in long-lived assets because additional asset retirement costs will be recognized as part of the carrying amounts of the assets.

FIN 47 clarifies that the term conditional asset retirement obligation as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations”, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though the uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

This statement will be effective for the fiscal year ended March 31, 2006 for the Company. The adoption of FIN 47 is not expected to have a material impact on the Company’s results of operations or its financial position.

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, 2005 and 2004, respectively, 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 fiscal year ended March 31, 2005 was approximately 1.58 percent.

Commodity Risk: In conjunction with divestiture of its generating business in 1998, NEP transferred its entitlement to power procured under several long-term contracts to USGen New England, Inc. (USGen). USGen agreed to fulfill NEP’s performance obligations under these contracts. The contract to purchase electricity and the assignment of this contract to USGen were recorded in accordance with FAS 133, as amended and interpreted, resulting in an offsetting derivative asset and derivative liability. The procurement contracts are exposed to commodity price risk arising from market price fluctuations in the cost of electricity. However, even though the Company is exposed to commodity price risk, it has a rate making mechanism that allows for the recovery of the cost of electricity from its customers.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A. FINANCIAL STATEMENTS

	•		Report of Independent Registered Public Accounting Firm

	•		Statements of Income, Statements of Retained Earnings and Statements of Comprehensive Income for the fiscal years ended March 31, 2005, 2004 and 2003

	•		Balance Sheets at March 31, 2005 and 2004

	•		Statements of Cash Flows for the fiscal years ended March 31, 2005, 2004 and 2003

	•		Notes to Financial Statements

Report of Independent Registered Public Accounting Firm

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, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended March 31, 2005 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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.

As discussed in Note N to the accompanying financial statements, the Company has restated its financial statements for the years ended March 31, 2004 and 2003.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP

Boston, Massachusetts
May 18, 2005,
except for the USGen New England, Inc. settlement section
of Note B as to which the date is June 9, 2005
and for Note N as to which the date is July 6, 2005.

New England Power Company
Statements of Income


	Year Ended March 31,
(In thousands)	2005			2004			2003
				(Restated) (See Note N)			(Restated) (See Note N)

Operating revenue, principally from affiliates (Note A)	$	458,261		$	464,178		$	518,248

Operating expenses:
Purchased electric energy:
Contract termination and nuclear unit shutdown charges		149,140			145,517			161,583
Other		13,057			14,387			31,389
Other operation		62,055			60,317			55,195
Maintenance		11,206			14,498			22,666
Depreciation and amortization: (Note A)
Amortization of stranded costs		67,344			70,710			72,394
Other		19,480			18,011			25,261
Taxes, other than income taxes (Note K)		16,373			16,957			18,868
Income taxes (Note G)		35,112			45,024			47,429

Total operating expenses		373,767			385,421			434,785

Operating income		84,494			78,757			83,463
Other income:
Allowance for equity funds used during construction (Note A)		859			680			467
Equity in income of nuclear power companies		1,269			1,675			4,554
Other income, net		2,042			2,533			76

Operating and other income		88,664			83,645			88,560

Interest expense:
Interest on long-term debt		7,806			5,875			7,694
Other interest		4,103			1,363			1,231
Allowance for borrowed funds used during construction (Note A)		(53	)		(36	)		(34	)

Total interest		11,856			7,202			8,891

Net income	$	76,808		$	76,443		$	79,669

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

New England Power Company
Statements of Comprehensive Income


	Year Ended March 31,
(In thousands)	2005			2004		2003
				(Restated) (See Note N)		(Restated) (See Note N)

Net income	$	76,808		$	76,443	$	79,669
Unrealized gain (loss) on securities, net of tax		(1	)		317		(120	)

Comprehensive income (Note A)	$	76,807		$	76,760	$	79,549

New England Power Company
Statements of Retained Earnings


	Year Ended March 31,
(In thousands)	2005			2004			2003
				(Restated) (See Note N)			(Restated) (See Note N)

Retained earnings at beginning of period	$	220,772		$	221,654		$	142,056
Net income		76,808			76,443			79,669
Dividends declared on cumulative preferred stock		(72	)		(75	)		(82	)
Dividends declared on common stock		—			(77,250	)		—
Gain on redemption of preferred stock		—			—			11

Retained earnings at end of period	$	297,508		$	220,772		$	221,654

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

New England Power Company
Balance Sheets


At March 31 (In thousands)	2005		2004
			(Restated) (See Note N)

Assets
Utility plant, at original cost (Note A)	$	966,086	$	878,824
Less accumulated provisions for depreciation and amortization		253,281		240,203

		712,805		638,621
Construction work in progress		37,456		12,852

Net utility plant		750,261		651,473

Goodwill (Note A)		338,188		338,188
Investments:
Equity investments in nuclear power companies (Note C)		17,659		18,305
Nonutility property and other investments		12,341		11,290

Total investments		30,000		29,595

Current assets:
Cash and cash equivalents (including $307,325 and $229,400 with affiliates)		311,396		229,716
Accounts receivable:
Affiliated companies		46,645		52,869
Others (less reserves of $153 and $153)		102,639		104,338
Fuel, materials and supplies, at average cost		3,560		2,054
Prepaid and other current assets		1,345		1,370
Deferred federal and state income taxes		—		202
Regulatory assets – purchased power obligations		104,486		105,011

Total current assets		570,071		495,560

Regulatory assets (Note B)		912,105		1,143,353
Additional minimum pension liability regulatory asset (Note B)		56,359		62,454
Prepaid pension asset		13,763		7,293
Deferred charges and other assets		5,161		5,374

Total assets	$	2,675,908	$	2,733,290

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

New England Power Company
Balance Sheets


At March 31 (In thousands)	2005		2004
			(Restated) (See Note N)

Capitalization and Liabilities
Capitalization:
Common stock, par value $20 per share,
Authorized – 6,449,896 shares
Outstanding – 3,619,896 shares	$	72,398	$	72,398
Other paid-in capital		731,974		731,974
Retained earnings		297,508		220,772
Accumulated other comprehensive income (Note A)		85		87

Total common equity		1,101,965		1,025,231
Cumulative preferred stock, par value $100 per share (Note I)		1,112		1,274
Long-term debt (Note E)		410,304		410,297

Total capitalization		1,513,381		1,436,802

Current liabilities:
Accounts payable (including $38,313 and $34,814 to affiliates)		67,845		59,620
Accrued liabilities:
Taxes		10,485		6,742
Deferred federal and state income tax		1,427		—
Interest		802		532
Purchased power obligations		104,486		105,011
Other accrued expenses		10,270		3,216
Dividends payable		17		19

Total current liabilities		195,332		175,140

Deferred federal and state income taxes		215,612		245,578
Unamortized investment tax credits		7,447		7,885
Accrued Yankee nuclear plant costs (Note D)		221,540		269,997
Purchased power obligations		189,126		293,296
Other reserves and deferred credits		333,470		304,592
Commitments and contingencies (Note D)

Total capitalization and liabilities	$	2,675,908	$	2,733,290

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

New England Power Company
Statements of Cash Flows


	Year Ended March 31,
(In thousands)	2005			2004			2003
				(Restated)			(Restated)
				(See Note N)			(See Note N)

Operating activities:
Net income	$	76,808		$	76,443		$	79,669
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of stranded costs		67,344			70,710			72,394
Other depreciation and amortization		19,480			18,011			25,261
Deferred income taxes and investment tax credits, net		(24,109	)		(26,281	)		8,124
Allowance for funds used during construction		(912	)		(716	)		(501	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable, net		7,923			(19,163	)		(28,842	)
Decrease in regulatory assets		162,059			171,998			79,526
(Increase) decrease in prepaid and other current assets		(722	)		(1,514	)		5,680
Increase (decrease) in accounts payable		8,225			(6,936	)		(4,912	)
Decrease in purchased power contract obligations		(104,695	)		(111,620	)		(151,533	)
Increase (decrease) in other current liabilities		7,089			(39,938	)		48,202
Decrease in other non-current liabilities		(56,870	)		(56,251	)		(30,538	)
Other, net		(831	)		9,775			(639	)

Net cash provided by operating activities	$	160,789		$	84,518		$	101,891

Investing activities:
Proceeds from sale of generating assets, net	$	—		$	—		$	84,300
Return of capital from equity investment		—			11,977			—
Plant expenditures, excluding allowance for funds used during construction		(78,873	)		(41,318	)		(41,980	)
Other investing activities		—			4,207			226

Net cash (used in) provided by investing activities	$	(78,873	)	$	(25,134	)	$	42,546

Financing activities:
Dividends paid on common stock	$	—		$	(77,250	)	$	—
Dividends paid on cumulative preferred stock		(74	)		(75	)		(85	)
Preferred stock – retirements		(162	)		(21	)		(141	)

Net cash used in financing activities	$	(236	)	$	(77,346	)	$	(226	)

Net increase (decrease) in cash and cash equivalents	$	81,680		$	(17,962	)	$	144,211
Cash and cash equivalents at beginning of period	$	229,716		$	247,678		$	103,467

Cash and cash equivalents at end of period	$	311,396		$	229,716		$	247,678


Supplementary Information:
Interest paid, less amounts capitalized	$	9,487		$	5,975		$	7,535
Federal and state income taxes paid (refunded)	$	62,352		$	114,915		$	(4,467	)
Dividends received from investments at equity	$	2,837		$	5,169		$	5,984

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

New England Power
Notes to Financial Statements

NOTE A — ACCOUNTING POLICIES

Basis of Presentation: New England Power Company (the Company or NEP), 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 in the United States of America (GAAP), including the accounting principles for rate-regulated entities (see Note B “Rate and Regulatory”), 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 electricity 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. In addition, the Company holds a minority joint ownership interest in one fossil fuel generating unit. The Company also owns minority equity interests in three companies, which own nuclear generating facilities that are permanently retired and are conducting decommissioning operations. Additionally, the Company sold a minority interest in a jointly owned nuclear generating unit in November 2002 and redeemed its minority ownership interest in another nuclear generating company in November 2003.

Goodwill: The Company’s goodwill of $338 million is primarily a result of the merger of New England Electric System and a subsidiary of National Grid Transco plc and the acquisition of Eastern Utilities Associates by National Grid USA (a wholly owned subsidiary of National Grid Transco plc). In accordance with Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets”, goodwill can no longer be amortized and must be reviewed for impairment at least annually and when events or circumstances indicate that the asset may be impaired. 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 impairment adjustment to the goodwill carrying value was required.

Use of Estimates: The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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 Allowance for Funds Used During

New England Power
Notes to Financial Statements

Construction. 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 (AFUDC): The Company capitalizes AFUDC as part of construction costs. AFUDC represents an allowance for the cost of funds used to finance construction. AFUDC 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 AFUDC rates were 7.9 percent, 7.8 percent and 7.7 percent for the years ended March 31, 2005, 2004 and 2003, respectively. AFUDC is segregated into its two components, borrowed funds and other funds, and is reflected in the “Interest” and “Other income” sections, respectively, in the Company’s Statements of Income. The amounts of AFUDC credits were recorded as follows:


	Year Ended March 31,
(In thousands)	2005		2004		2003

Other income	$	859	$	680	$	467
Interest	$	53	$	36	$	34

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


	Year Ended March 31,
(In thousands)	2005		2004		2003

Amortization of stranded costs:
Purchased power contract buyout	$	64,290	$	65,462	$	58,490
Regulatory assets covered by contract termination charges (Note B)		3,054		5,248		12,236
Nuclear fuel		—		—		1,668

Total amortization of stranded costs	$	67,344	$	70,710	$	72,394


Other depreciation and amortization:
Depreciation — transmission related	$	19,267	$	17,863	$	17,079
Depreciation — all other		213		148		1,011
Nuclear decommissioning costs		—		—		7,171

Total other depreciation and amortization expense	$	19,480	$	18,011	$	25,261

New England Power
Notes to Financial Statements

Amortization of purchased power contracts and regulatory assets covered by contract termination charges (CTCs) is provided over the recovery period as allowed in the applicable regulatory agreement. Depreciation is provided annually on a straight-line basis. The provision for depreciation as a percentage of weighted average depreciable transmission property was 2.27 percent for all periods presented.

Revenues: The Company has two primary sources of revenue: transmission and stranded cost recovery. Transmission revenues are based on a formula rate that recovers the Company’s actual costs plus a return on investment. Stranded cost recovery revenues are collected through a CTC, which is billed to former wholesale customers of the Company in connection with the Company’s divestiture of its electricity generation investments.

Federal and State Income Taxes: Regulated federal and state income taxes are recorded under the provisions of Financial Accounting Standards Board (FASB) SFAS No. 109 “Accounting for 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 “Taxes”).

Service Company Charges: 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 $86 million, $64 million and $46 million including capitalized construction costs of $39 million, $15 million and $10 million for the years ended March 31, 2005, 2004 and 2003, respectively.

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

Derivatives: The Company accounts for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (FAS 133), and SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” as amended. Under the provisions of FAS 133, all derivatives except those qualifying for the normal purchase/normal sale exception are recognized on the balance sheet at their fair value. Fair value is determined using current quoted market prices.

Comprehensive Income: 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 consist of unrealized gains and losses on marketable equity investments. For the fiscal years ended March 31, 2005, 2004 and 2003 tax expense/(benefit) related to other comprehensive income were approximately $(1,000), $205,000 and $(78,000), respectively.

New England Power
Notes to Financial Statements

Paragraph 40 of the FASB SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” requires that presently enacted changes in laws impacting employer-sponsored retiree health care programs which take effect in future periods be considered in current-period measurements for benefits expected to be provided in those future periods. Therefore, under FAS 106 guidance, measures of plan liabilities and annual expense on or after the date of enactment should reflect the effects of this Act. Pursuant to guidance from the FASB under FSP FAS 106-2, the retiree health obligations will reflect the estimated subsidy payments expected from the federal government for the participant groups anticipated to qualify for the subsidy. Participant groups who are not expected to qualify, or have not yet been determined whether they will qualify, for the federal subsidy will not impact the retiree health obligations. If any portion of this group is subsequently determined to qualify for the subsidy, the retiree health care obligations will be adjusted at the time of that determination. The Company has chosen to apply the guidance prospectively, impacting retiree health costs. The Company adopted the provisions of FAS 106-2 on July 1, 2004. Reduced expense resulting from the Act of approximately $1 million was credited to customers. See Note H “Employee Benefits”.

New England Power
Notes to Financial Statements

Reclassifications: Certain amounts from prior years have been reclassified on the accompanying financial statements to conform to the fiscal 2005 presentation.

NOTE B – RATE AND REGULATORY

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

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

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

New England Power
Notes to Financial Statements

As a result of applying FAS 71, the Company has recorded net regulatory assets for the costs that are recoverable from customers through CTCs or through transmission rates. The following table details regulatory assets and liabilities summarized in the Company’s financial statements:


	March 31,
(In thousands)	2005			2004
				(Restated)
				(See Note N)

Regulatory assets – current
Purchased power payment obligations	$	104,486		$	105,011

Total current regulatory assets	$	104,486		$	105,011

Regulatory assets – non-current
Purchased power payment obligations	$	189,126		$	293,296
Purchased power contracts bought-out		193,829			255,724
Accrued Yankee nuclear decommissioning costs		221,540			269,997
Additional minimum pension liability (Note H)		56,359			62,454
Other regulatory assets		307,610			324,336

Total regulatory assets non-current	$	968,464		$	1,205,807

Total regulatory assets	$	1,072,950		$	1,310,818

Regulatory liabilities included in other reserves and deferred credits:
CTC related liabilities	$	(152,412	)	$	(167,299	)
Pensions and other post-retirement employee benefits		(43,933	)		(47,682	)

Total regulatory liabilities	$	(196,345	)	$	(214,981	)

Net regulatory assets	$	876,605		$	1,095,837

Purchase power payment obligations: When it divested its generating business, the Company transferred its entitlement to power procured under several long-term contracts (the Contracts) to USGen New England Inc. (USGen), Constellation Power Source, Inc. and TransCanada Power Marketing Ltd. (collectively the Buyers). The Buyers agreed to fulfill the Company’s performance and payment obligations under the Contracts. At the same time the Company agreed to pay the Buyers a fixed amount monthly for the above-market cost of the Contracts. (The contract transferring Contracts to Constellation Power Source has since been terminated because it was fully performed in accordance with its terms. The Company has since resumed performance and payment obligations under the Contracts that were transferred to USGen, as described in the “USGen New England, Inc. settlement” below.) These fixed payments by the Company were $91 million and $92 million for fiscal years 2005 and 2004, respectively. The net present value of these fixed monthly payments is recorded as a liability with an equal amount recorded in regulatory assets representing the future collection of the liability from ratepayers. At March 31, 2005 and 2004, the net present value of the liability for the fixed monthly payment is approximately $294 million and $398 million, respectively.

Purchase power contracts bought-out: In conjunction with divestiture, the Company has made lump sum payments to effectively terminate a number of purchase power contracts. These payments are recorded as regulatory assets and are amortized as they are recovered from customers.

Accrued Yankee nuclear decommissioning costs: The regulatory asset represents the estimated future decommissioning billings from the Yankees. Under settlement agreements, the Company is permitted to recover prudently incurred decommissioning costs through CTC’s. For a discussion of decommissioning nuclear units, see Note D – Commitments and Contingencies.

Additional minimum pension liability: The offset to any additional minimum pension liability associated with the Company’s qualified pension plan is applied to this regulatory asset on a pre-tax basis instead of after-tax to other comprehensive income as determined by regulatory rulings.

Other regulatory assets: Included in the other regulatory asset is the accumulation of numerous miscellaneous regulatory deferrals. This largely consists of unrecovered costs associated with divested fixed assets that are being recovered through the CTC.

CTC related liabilities: CTC related liabilities consist of obligations to customers that resulted from the sale of certain stranded assets. These amounts are being refunded to customers as determined per rate filings.

Pensions and other post-retirement employee benefits: As a result of the fiscal 2000 merger of the Company with National Grid and the fiscal 2001 acquisition of Montaup Electric Co, the Company revalued its pension and other post-retirement benefit plans in accordance with FAS 87 and FAS 106 and recognized previously unrecognized net gains in these benefit plans. The recognition of these gains was offset on the balance sheet by the establishment of a regulatory liability which is being passed back to customers over a 15 year period.

New England Power
Notes to Financial Statements

USGen New England, Inc. Settlement: USGen had previously filed for bankruptcy protection on July 8, 2003. The Company reached a settlement with USGen regarding all matters between the parties, which was approved by the bankruptcy court on December 22, 2004. Under the settlement, on April 1, 2005, the agreement by which the Company transferred the Contracts to USGen was terminated. The Company resumed the performance and payment obligations under the contracts that had been transferred to USGen and removed the related liability from the balance sheet and offsetting regulatory asset for the above market portion of the Contracts with USGen of approximately $246 million. The Company continues to record a derivative liability of $404 million for the above-market portion of the Contracts with an equal offset to a corresponding regulatory asset. The performance and payment obligations will not materially affect the results of operations, as the Company will recover the above-market cost of the Contracts from customers through the CTC. In accordance with the settlement, the Company received proceeds of approximately $195.8 million on June 8, 2005 and June 9, 2005 from USGen. That amount relates in part to the Contracts and the Company has filed a plan with regulators to credit the $195.8 million to customers through the CTC.

The settlement between the Company and USGen also resolved the Company’s claims with respect to the Hydro Quebec transmission line agreements (HQ Transmission Line Agreements), under which USGen was obligated to reimburse the Company for monthly costs of approximately $1 million. As of April 2, 2004, the Company resumed performance and payment under the HQ Transmission Line Agreements. The Company’s resumption of performance and payment obligations has not affected the results of operations, as the Company is recovering any remaining costs of the HQ Transmission Line Agreements from its customers through the CTC. The payment received from USGen relates in part to the HQ Transmission Line Agreements and, as noted above, the Company has filed a plan with regulators to credit the $195.8 million to customers through the CTC.

Pension: The Company has recognized an additional minimum pension liability for the years ended March 31, 2005 and 2004 of approximately $35 million and $40 million, respectively. 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 – NUCLEAR INVESTMENTS

Yankee Nuclear Power Companies: At March 31, 2005, the Company has minority interests in Yankee Atomic Electric Company, Connecticut Yankee Atomic Power Company and Maine Yankee Atomic Power Company (together, the Yankees), which own nuclear generating units that have been permanently retired and are conducting decommissioning operations. These ownership interests are

New England Power
Notes to Financial Statements

accounted for on the equity method. The Company also previously had a minority interest in a fourth company, Vermont Yankee Nuclear Power Corporation (Vermont Yankee) which it redeemed in November 2003. Vermont Yankee sold its nuclear generating unit in July 2002. The Company has power contracts with each of the 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 and Vermont Yankee:


	Year Ended March 31,
(In thousands)	2005			2004			2003

Operating revenue	$	172,588		$	270,392		$	283,609

Net income	$	4,966		$	8,174		$	20,828

Company’s equity in net income	$	1,086		$	1,674		$	4,554

Net plant	$	1,777		$	2,099		$	2,132
Other assets	$	1,294,580		$	1,470,306		$	1,608,191
Liabilities and debt	$	(1,214,564	)	$	(1,387,527	)	$	(1,447,168	)

Net assets	$	81,793		$	84,878		$	163,155

Company’s equity in net assets	$	17,659		$	18,305		$	36,749

Company’s purchased electricity:
Yankees and Vermont Yankee	$	44,212		$	37,507		$	33,400

At March 31, 2005 and 2004, approximately $1 million and $2 million, respectively, of undistributed earnings of the Yankees were included in the Company’s retained earnings.

NOTE D – COMMITMENTS AND CONTINGENCIES

Decommissioning Nuclear Units: The Yankees own nuclear generating units that have been permanently retired and are conducting decommissioning operations. These three units are as follows:

The Company’s

Future Estimated

Investment as of

Billings to the

March, 31 2005

Company

Unit

$(millions)

Date Retired

$(millions)

Yankee Atomic

34.5

0.3

Feb 1992

Connecticut Yankee

19.5

8.7

Dec 1996

118

Maine Yankee

24.0

8.7

Aug 1997

With respect to each of the units, the Company has recorded a liability and a regulatory asset reflecting the estimated future decommissioning billings from the Yankees. In a 1993 decision, the FERC

New England Power
Notes to Financial Statements

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 Yankees collect the approved costs from their purchasers, including NEP. The Company’s share of the decommissioning costs is accounted for in “Purchased electric energy” on the income statement. Under settlement agreements, the Company is permitted to recover prudently incurred decommissioning costs through CTCs.

The Yankees are periodically required to file rate cases, presenting the Yankees’ estimates of future decommissioning costs for FERC approval. Yankee Atomic and Maine Yankee are currently collecting decommissioning and other costs under FERC Orders issued in their respective rate cases. Connecticut Yankee is also collecting costs, subject to refund under a rate case now pending at the FERC, as described below.

Future estimated billings from the Yankees are based on decommissioning cost estimates. These estimates include the projected costs of decontaminating the units as required by the Nuclear Regulatory Commission, dismantling the units, security, liability and property insurance and other costs. They also include costs for interim spent fuel storage facilities, which the Yankees have constructed during litigation they brought to enforce the Department of Energy’s obligation to remove the fuel as required by the Nuclear Waste Policy Act of 1982. A trial at the U.S. Court of Federal Claims to determine the level of damages has concluded and the parties are awaiting an order. Any damages received by the Yankees would be applied to reduce the decommissioning and other costs collected from their purchasers. The decommissioning costs that are actually incurred by the Yankees may exceed the estimated amounts, perhaps substantially.

Connecticut Yankee Rate Filing, Prudence Challenge and Other Proceedings: On July 1, 2004, Connecticut Yankee filed with the FERC seeking a rate increase to reflect increased costs for decommissioning, pensions and other employment benefits, increased security and insurance costs and other expenses. In aggregate, the increase amounts to approximately $396 million through 2010, NEP’s share of which is included in the future estimated billings shown in the table above. The rate case also reflects the impact of the termination of a fixed price contract with Bechtel Power Corporation to perform decommissioning operations and projects a substantial increase in costs over and delay in completion compared with those previously projected.

The Connecticut Department of Public Utility Control and the Connecticut Office of Consumer Counsel (together, the Department) have intervened at the FERC requesting that the FERC reject Connecticut Yankee’s rate filing, or in the alternative, disallow a portion of the requested rate increase on the ground that $205 million to $235 million of these costs were imprudently incurred. Bechtel and three New England states have also intervened, asserting that these costs are imprudent and should be disallowed. FERC authorized Connecticut Yankee to begin charging the proposed new rates effective

New England Power
Notes to Financial Statements

February 1, 2005, subject to refund. Hearings on the rate increase filing at FERC were held in June, and initial briefs are due in August.

Prior to Connecticut Yankee’s filing, the Department petitioned the FERC to determine that Connecticut Yankee’s purchasers, including NEP, were obliged to pay for all of Connecticut Yankee’s decommissioning costs, whether or not prudent, and could not pass on any imprudent costs to their retail customers. The FERC denied the petition on the ground that it has no jurisdiction over retail rates. The Department and Bechtel moved for clarification and rehearing. FERC has not yet ruled on this motion.

Connecticut Yankee and Bechtel are litigating the termination of the fixed price contract in Connecticut state court, with each party seeking substantial damages. Trial is scheduled to commence in mid-2006.

Hydro-Quebec Interconnection: Three affiliates of the Company were created to construct and operate transmission facilities to transmit power from Hydro-Quebec to New England. Under the financial and organizational agreements (the Support Agreements) entered into at the time these facilities were constructed, the Company agreed to guarantee a portion of the project debt. At March 31, 2005, the Company had guaranteed approximately $13 million of project debt with terms through 2015. As discussed in further detail in Note B “Rate and Regulatory”, the Company entered into the HQ Transmission Line Agreements with the purchaser of its nonnuclear generation, USGen, under which USGen assumed the Company’s rights to use the Hydro-Quebec line and also agreed to reimburse the Company for its payment obligations under the Support Agreements. The HQ Transmission Line Agreements terminated on April 1, 2004 and the Company has resumed performance and payment obligations under this 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 from the Company’s customers through CTCs.

Millstone 3 Prudence Challenge: In November 1999, NEP agreed with Northeast Utilities (NU) to settle certain claims. As part of the agreement, NU agreed to include NEP’s 16.2 percent ownership interest in Millstone Unit 3 in an auction of NU’s share of the unit. Upon the closing of the sale, NEP was to receive a fixed amount, regardless of the actual sale price. In March 2001, the Millstone units were sold, including NEP’s interest, for $1.3 billion. In accordance with the settlement, NEP was paid approximately $25 million for its interest in the unit (plus reimbursement of pre-paid amounts), from which NEP paid approximately $6.2 million to increase the decommissioning trust fund.

In the past, regulatory authorities from Rhode Island, New Hampshire and Massachusetts expressed an intent to challenge the reasonableness of the settlement agreement on various grounds, taking the position that NEP would have received approximately $140 million of sale proceeds if there had been no agreement with NU. The matter has been resolved in New Hampshire and Massachusetts. In the event that Rhode Island proceeds with a challenge, the dispute will be resolved by the FERC.

New England Power
Notes to Financial Statements

Management believes that the Company acted prudently because, among other reasons, the amount it received under the settlement agreement was the highest sale price for a nuclear unit at the time the agreement was reached.

Town of Norwood Dispute: From 1983 until 1998, NEP was the wholesale power supplier for Norwood. In April 1998, Norwood began taking power from another supplier, although its contract term with NEP ran to 2008. Pursuant to a tariff amendment approved by the FERC in May 1998, NEP has been assessing Norwood a CTC. Through March 31, 2005, the charges assessed Norwood but not paid amount to approximately $77.7 million. Norwood made a payment of approximately $20 million in July 2004. NEP and Norwood are engaged in litigation and at the FERC, as follows.

State Collection Action: NEP filed a collection action in Massachusetts Superior Court (Worcester County) to collect the CTC, which Norwood has refused to pay, apart from the initial payment in 2004. 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. Following unsuccessful appeals by Norwood, the Superior Court entered judgment for NEP on June 9, 2004 in the amount of approximately $43.3 million, based on amounts owed through January 31, 2001. Norwood continues to contest the judgment in the Massachusetts Appeals Court.

FERC 206 Proceeding: In December 2002, Norwood filed a challenge to the CTC rate with the FERC under Section 206 of the Federal Power Act. Under this Section, the FERC has the power to grant prospective relief only. In an order dated July 2, 2003, the FERC set down for hearing Norwood’s challenge to the factors used to calculate the CTC rate for Norwood, and set a refund effective date of February 21, 2003, which empowers the FERC to direct NEP to adjust Norwood’s liability for unpaid charges billed after that date in the event that Norwood’s challenge is successful. On June 9, 2004, the FERC administrative law judge issued an initial decision recommending that FERC revise the CTC formula to reduce the CTC amount that was previously calculated under the formula which the FERC accepted and approved in 1998. On July 9, 2004, NEP filed a brief objecting to this initial decision, arguing that no reduction is appropriate. Norwood and the FERC staff have also challenged the initial decision, arguing that the reduction is not enough. The challenges are now under consideration by FERC and the parties are awaiting a decision.

Plant Expenditures: The Company’s utility plant expenditures are estimated to be approximately $91 million for 2006. At March 31, 2005, substantial commitments had been made relative to normal operating future planned expenditures.

New England Power
Notes to Financial Statements

NOTE E – LONG-TERM DEBT

A summary of long-term debt is as follows:

At March 31 (In thousands)

Series

Rate %

Maturity

2005

2004

Pollution Control Revenue Bonds:

CDA (a)

Variable

October 15, 2015

38,500

38,500

MIFA 1 (b)

Variable

March 1, 2018

79,250

79,250

BFA 1 (c)

Variable

November 1, 2020

135,850

135,850

BFA 2 (c)

Variable

November 1, 2020

50,600

50,600

MIFA 2 (b)

Variable

October 1, 2022

106,150

106,150

Unamortized discounts

(46

)

(53

)

Total long-term debt

410,304

410,297

(a)		CDA = Connecticut Development Authority

(b)		MIFA = Massachusetts Industrial Finance Authority (now known as Massachusetts Development Finance Agency)

(c)		BFA = Business Finance Authority of the State of New Hampshire

At March 31, 2005, interest rates on the Company’s variable rate long-term bonds ranged from 1.90 percent to 2.18 percent. There are no payments or sinking fund requirements due in 2005 through 2008.

At March 31, 2005, 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 F — SHORT-TERM BORROWINGS

At March 31, 2005 and 2004, the Company had no short-term debt outstanding. The Company has regulatory approval to issue up to $375 million of short-term debt. National Grid USA and certain subsidiaries, including the Company, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies that invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice.

At March 31, 2005 and 2004, the Company had lines of credit and standby bond purchase facilities with banks totaling $440 million and $439 million, respectively, which is available to provide

New England Power
Notes to Financial Statements

liquidity support for $410 million of the Company’s long-term bonds in tax-exempt commercial paper mode, and for other corporate purposes. The agreement with banks that provide the Company’s line of credit and standby bond purchase facility expires on November 29, 2009, subject to regulatory approval. The Company plans to seek such regulatory approval later this year. There were no borrowings under these lines of credit at March 31, 2005. Fees are paid on the lines and facilities in lieu of compensating balances.

NOTE G – TAXES

NGUSA and its subsidiaries (including the Company) participate with National Grid General Partnership, a wholly owned subsidiary of NGT, 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 March 22, 2000.

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


	Year Ended March 31,
(In thousands)	2005		2004		2003
			(Restated)		(Restated)
			(See Note N)		(See Note N)

Income taxes charged to operations	$	35,112	$	45,024	$	47,429
Income taxes charged to “Other income”		2,319		2,727		1,443

Total income taxes	$	37,431	$	47,751	$	48,872

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


	Year Ended March 31,
(In thousands)	2005			2004			2003
				(Restated)			(Restated)
				(See Note N)			(See Note N)

Current income taxes	$	61,540		$	74,031		$	40,748
Deferred income taxes		(23,671	)		(25,839	)		8,593
Investment tax credits, net		(438	)		(441	)		(469	)

Total income taxes	$	37,431		$	47,751		$	48,872

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 was credited to other income pursuant to federal tax law. Previously recognized ITC related to transmission facilities is amortized over the estimated productive lives.

New England Power
Notes to Financial Statements

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


	Year Ended March 31,
(In thousands)	2005			2004		2003
				(Restated)		(Restated)
				(See Note N)		(See Note N)

Federal income taxes	$	38,355		$	42,552	$	43,009
State income taxes		(924	)		5,199		5,863

Total income taxes	$	37,431		$	47,751	$	48,872

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:


	Year Ended March 31,
(In thousands)	2005			2004			2003
				(Restated)			(Restated)
				(See Note N)			(See Note N)

Computed tax at statutory rate	$	39,984		$	43,468		$	44,989
Increases (reductions) in tax resulting from:
Settlement of tax audits		(3,349	)		—			—
Tax return true-ups		154			(157	)		582
Amortization of investment tax credits		(285	)		(286	)		(305	)
State income taxes, net of federal income tax benefit		(601	)		3,379			3,811
Flow through adjustments		1,856			1,769			1,103
All other differences		(328	)		(422	)		(1,308	)

Total income taxes	$	37,431		$	47,751		$	48,872

The Company applies the provision of 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.

New England Power
Notes to Financial Statements

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


At March 31 (In millions)	2005			2004
				(Restated) (See Note N)

Deferred tax asset:
Plant related	$	1		$	1
Investment tax credits		3			3
All other		104			103

		108			107

Deferred tax liability:
Plant related		(307	)		(302	)
All other, principally regulatory assets		(18	)		(50	)

		(325	)		(352	)

Net deferred tax liability	$	(217	)	$	(245	)

There were no valuation allowances for deferred tax assets at March 31, 2005 or 2004.

NOTE H – EMPLOYEE BENEFITS

Summary

The Company has a non-contributory defined benefit pension plan and a post-retirement benefit plan (the Plans) covering substantially all employees. The pension is a noncontributory, tax-qualified defined benefit plan which provides all employees of National Grid USA and its subsidiaries with a minimum retirement benefit. Under the pension plan 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. Non-union employees hired after July 15, 2002 participate under a noncontributory defined benefit cash balance design.

Supplemental nonqualified, non-contributory executive retirement programs provide additional defined pension benefits for certain executives.

The post-retirement benefit other than pensions (PBOP) plan 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.

Funding Policy

Absent unusual circumstances, the Company’s funding policy is to contribute to the plans each year the maximum tax-deductible amount 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.

New England Power
Notes to Financial Statements

Investment Strategy

The Company manages the Plans’ investments to minimize the long-term cost of operating the Plans, with a reasonable level of risk. Risk tolerance is determined as a result of a periodic asset/liability study which analyzes the plans’ liabilities, and funded status and results in the determination of the allocation of assets across equity and fixed income. Equity investments are broadly diversified across U.S. and non-U.S. stocks, as well as across growth, value and small and large capitalization stocks. Likewise, the fixed income portfolio is broadly diversified across the various fixed income market segments. Small investments are also held in private equity, real estate and timber, with the objective of enhancing long-term returns while improving portfolio diversification. Investment risk and return is reviewed by an investment committee on a quarterly basis.

The target asset allocation for the plans is:


	Pension Benefits						PBOP
	2005			2004			2005			2004

U.S. Equities		44	%		47	%		50	%		50	%
Global Equities (including U.S.)		7	%		—			—			—
Non-U.S. Equities		11	%		15	%		15	%		15	%
Fixed Income		35	%		35	%		35	%		35	%
Private Equity and Property		3	%		3	%		—			—

		100	%		100	%		100	%		100	%

Expected Rate of Return on Assets

The estimated rate of return for various passive asset classes is based both on analysis of historical rates of return and forward looking analysis of risk premiums and yields. Current market conditions, such as inflation and interest rates, are evaluated in connection with the setting of our long-term assumption. A small premium is added for active management of both equity and fixed income. The rates of return for each asset class are then weighted in accordance with our target asset allocation, and the resulting long-term return on asset rate is then applied to the market-related value of assets.

Pension Benefits: The Company’s net pension cost for the years ended March 31, 2005, 2004 and 2003 included the following components:


	Year Ended March 31,
(In thousands)	2005			2004			2003

Service cost-benefits earned during the period	$	66		$	148		$	729
Plus (less):
Interest cost on projected benefit obligation		7,318			7,688			8,954
Return on plan assets at expected long-term rate		(9,480	)		(9,320	)		(12,500	)

New England Power
Notes to Financial Statements


	Year Ended March 31,
(In thousands)	2005		2004		2003

Amortization of net loss		2,691		2,710		—
Amortization of prior service cost		184		184		209
Curtailment loss		—		10		—

Benefit (income)/cost	$	779	$	1,420	$	(2,608	)

Special termination benefits not included above	$	—	$	963	$	—

The following weighted average assumptions were used to determine the net periodic pension cost.


	Year Ended March 31,
	2005			2004			2003

Discount rate		5.75	%		6.25	%		7.50	%
Rate of compensation increase		4.70	%		4.63	%		4.63	%
Expected return on plan assets		8.50	%		8.50	%		8.75	%

The funded status of the pension plan cannot be presented separately for the Company as the Company participates in the plan with certain other National Grid USA subsidiaries.

The following table provides a reconciliation of the changes in the National Grid companies’ pension plan’s fair value of assets for the fiscal years ended March 31, 2005 and 2004.


(In millions)	2005			2004

Reconciliation of change in plan assets:
Fair value of plan assets at beginning of period	$	1,102		$	869
Actual return on plan assets during year		83			256
Company contributions		59			75
Benefits paid from plan assets		(113	)		(98	)

Fair value of plan assets at end of period	$	1,131		$	1,102

The following table provides a reconciliation of the National Grid companies’ pension plan’s percentage distribution of the fair market value of the types of assets held in the pension plan’s trust for the fiscal years ended March 31, 2005 and 2004.


	2005			2004

Distribution of plan assets:
Debt securities		34	%		34	%
Equity securities		64	%		63	%
Property/real estate		—			1	%
Other		2	%		2	%

		100	%		100	%

New England Power
Notes to Financial Statements

The expected contribution to the National Grid companies’ pension plan during fiscal year 2006 is approximately $59 million.

The following table provides the changes in the National Grid companies’ pension plan’s benefit obligations, reconciliation of the benefit obligation, funded status, amounts recognized in the balance sheet and the assumptions used in developing the obligations at March 31:


(In millions)	2005			2004

Accumulated benefit obligation	$	1,255		$	1,249

Change in benefit obligation:
Benefit obligation at beginning of period	$	1,425		$	1,258
Service cost		22			20
Interest cost		79			78
Actuarial loss		16			93
Benefits paid		(113	)		(98	)
Curtailments		—			(4	)
Special termination benefits		—			78

Benefit obligation at end of period	$	1,429		$	1,425


(In millions)	2005		2004

Funded status	$	(299)	$	(323	)
Unrecognized actuarial loss		545		543
Unrecognized prior service cost		13		14

Net amount prepaid	$	259	$	234

New England Power
Notes to Financial Statements


(In millions)	2005			2004

Amounts recognized on the balance sheet consist of:
Prepaid benefit asset	$	—		$	—
Accrued benefit liability		(125	)		(148	)
Intangible asset		15			16
Regulatory assets		56			62
Accumulated other comprehensive income		313			304

Net amount recognized on the balance sheet	$	259		$	234

The following weighted average assumptions were used to determine pension benefit obligation at March 31, 2005 and 2004.


	2005			2004

Discount rate		5.75	%		5.75	%
Average rate of increase in future compensation level		4.65	%		4.63	%
Expected long-term rate of return on assets		8.25	%		8.50	%

The following pension benefit payments, which reflect expected future services, as appropriate, are expected to be paid from the National Grid companies’ pension plan:


(In millions)	Pension Benefits

2006	$	94
2007	$	90
2008	$	86
2009	$	83
2010	$	85
2011-2015	$	465

Additional Minimum Liability (AML): Statement of Financial Accounting Standards 87 “Employers’ Accounting for Pensions” states that if a pension plan’s 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, 2004 and 2003 is greater than the fair value of plan assets. As such, at March 31, 2005 and 2004, the Company has recognized an additional minimum pension liability of $35 million and $40 million, respectively, on its balance sheet 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 capital markets recover such

New England Power
Notes to Financial Statements

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.

The Company has also recognized an allocated share of the additional minimum pension liability of its affiliated service company of approximately $23 million and $24 million at March 31, 2005 and 2004, respectively, which is recorded in accounts payable on the balance sheet with an offsetting charge to regulatory assets.

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, 2005, 2004 and 2003 included the following components:


	Year Ended March 31,
(In thousands)	2005			2004			2003

Service cost — benefits earned during the period	$	40		$	67		$	221
Plus (less):
Interest cost on projected benefit obligation		3,381			3,608			3,994
Return on plan assets at expected long-term rate		(3,339	)		(3,414	)		(3,841	)
Amortization of prior service cost		(25	)		(19	)		(12	)
Amortization of net loss		971			516			395
Curtailment (gain)/loss		—			215			—

Benefit cost	$	1,028		$	973		$	757

Special termination benefits not included above	$	—		$	196		$	—

The following weighted average assumptions were used to determine the net periodic post retirement benefits cost for the fiscal years ended March 31, 2005, 2004 and 2003.


	2005			2004			2003

Discount rate		5.75	%		6.25	%		7.50	%
Expected long-term rate of return on assets
Union		9.50	%		8.75	%		9.00	%
Non-union		5.75	%		7.25	%		7.50	%
Health care cost trend
Initial		10.00	%		10.00	%		10.00	%
Ultimate		5.00	%		5.00	%		5.00	%
Year ultimate rate reached		2009			2008			2007

The following table provides a reconciliation of the Company’s portion of the National Grid companies’ PBOP fair value of assets for the fiscal years ended March 31, 2005 and 2004.

New England Power
Notes to Financial Statements


(In millions)	2005			2004

Reconciliation of change in plan assets:
Fair value of plan assets at beginning of period	$	42		$	36
Actual return on plan assets during year		2			8
Company contributions		—			2
Benefits paid from plan assets		(4	)		(4	)

Fair value of plan assets at end of period	$	40		$	42

The following table provides the percentage distribution of the fair market value of the types of assets held in the PBOP’s trust at March 31.


	2005			2004

Distribution of plan assets:
Debt securities		45	%		38	%
Equity securities		54	%		61	%
Other		1	%		1	%

		100	%		100	%

The Company expects to contribute approximately $2 million to its PBOP plan in fiscal year 2006.

The following provides the PBOP plan’s reconciliation of the benefit obligation, funded status and the assumptions used in developing the obligations for the National Grid USA companies’ PBOP plan at March 31:


(In millions)	2005			2004

Change in benefit obligation:
Benefit obligation at beginning of period	$	67		$	67
Interest cost		3			4
Actuarial loss		(4	)		—
Benefits paid		(4	)		(4	)

Benefit obligation at end of period	$	62		$	67


(In millions)	2005			2004

Funded status	$	(22	)	$	(25	)
Unrecognized actuarial loss		29			32

Net amount recognized	$	7		$	7

New England Power
Notes to Financial Statements


	2005			2004

Discount rate		5.75	%		5.75	%
Expected long-term rate of return on assets
Union		8.50	%		9.00	%
Non-union		6.75	%		5.75	%
Health care cost trend
Initial		10.00	%		10.00	%
Ultimate		5.00	%		5.00	%
Year ultimate rate reached		2010			2009

The following PBOP benefit payments and subsidies, which reflect expected future service, as appropriate, are expected to be paid:


(In millions)	Payments		Subsidies

2006	$	5	$	—
2007	$	5	$	1
2008	$	5	$	1
2009	$	5	$	1
2010	$	5	$	1
2011-2015	$	25	$	3

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, 2005 by approximately $8 million or decrease the APBO by approximately $7 million, and increase or decrease the net post-retirement cost for the year by approximately $400,000.

Medicare Act of 2003: The Medicare Prescription Drug, Improvement and Modernization Act was signed into law on December 8, 2003. It created a new Medicare prescription drug benefit (Medicare Part D) and a federal subsidy to sponsors of retiree healthcare plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. On May 19, 2004, the FASB issued Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the FSP). The FSP provides guidance on accounting for the effects of the Act, which resulted in a reduction in the APBO for the subsidy related to benefits attributed to past service. The reduction in the APBO represents a deferred actuarial gain in the amount of $8 million for the Company’s postretirement benefits plan as of July 1, 2004. On January 21, 2005 final regulations were issued on the new Medicare prescription drug program. The impact on plan obligations as a result of the final regulations was not significant.

New England Power
Notes to Financial Statements

The net periodic benefit costs charged to the Company during the year ended March 31, 2005 included the following components:


(in thousands)	2005

Service cost	$	3
Interest cost		360
Recognized actuarial loss		281

Net periodic benefit cost	$	644

Annualized expense reduction	$	858

This reduction in expense was credited to the Company’s customers.

Voluntary Early Retirement Offers

At December 31, 2003, enrollment periods ended with respect to two voluntary early retirement offers (VEROs) made by National Grid USA. The VEROs did not affect the Company’s results of operations, as the Company is recovering the related expenses through cost recovery mechanisms. For the fiscal year ended March 31, 2004, the Company’s expense related to the VEROs was approximately $7 million.

No similar early retirement offers were made for the fiscal year ended March 31, 2005.

Defined contribution plan

The Company also has a defined contribution pension plan (employee savings fund plan) that covers substantially all employees. Employer matching contributions of approximately $10,000, $14,000 and $124,000 were expensed for the fiscal years ended March 31, 2005, 2004 and 2003.

NOTE I — PREFERRED STOCK

A summary of cumulative preferred stock at March 31, 2005 and 2004, respectively, is as follows (in thousands of dollars except for share data):


	Shares Outstanding				Amount				Dividends Declared
	2005		2004		2005		2004		2005		2004

$100 par value 6.00% Series (a)		11,117		12,734	$	1,112	$	1,274	$	72	$	75

(a) Noncallable.

New England Power
Notes to Financial Statements

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

NOTE J — SEGMENTS

The Company’s reportable segments are electricity transmission and stranded cost recoveries. The Company is engaged principally in the business of electricity 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 electricity transmission and stranded cost recoveries 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.


	Electricity		Stranded Cost
(In millions)	Transmission		Recoveries		Total

Year Ended March 31, 2005

Operating revenue	$	172	$	286	$	458
Operating income before income taxes		80		40		120
Depreciation and amortization		19		—		19
Amortization of stranded costs		—		67		67


Year Ended March 31, 2004 (Restated)

Operating revenue	$	180	$	284	$	464
Operating income before income taxes		77		47		124
Depreciation and amortization		18		—		18
Amortization of stranded costs		—		71		71


Year Ended March 31, 2003 (Restated)

Operating revenue	$	165	$	353	$	518
Operating income before income taxes		74		57		131
Depreciation and amortization		25		—		25
Amortization of stranded costs		—		72		72

New England Power
Notes to Financial Statements


	Total Assets
	2005		2004
(In millions) At March 31,			(Restated) (See Note N)


Electricity transmission	$	1,203	$	1,071
Stranded cost recoveries		1,133		1,404
Corporate assets		340		258

Total	$	2,676	$	2,733

NOTE K - SUPPLEMENTARY INCOME STATEMENT

Advertising expenses, expenditures for research and development and rents were not material and there were no royalties paid in the years ended March 31, 2005, 2004 and 2003. Taxes, other than income taxes, charged to operating expenses are set forth by class as follows:


	Year Ended March 31,
(In thousands)	2005		2004		2003

Municipal property taxes	$	14,663	$	15,364	$	16,800
Federal and state payroll and other taxes		1,710		1,593		2,068

Total taxes other than income taxes	$	16,373	$	16,957	$	18,868

Transactions between the Company and other affiliated companies for sales of electric energy and other sales amounted to approximately $311 million, $340 million and $324 million for the years ended March 31, 2005, 2004 and 2003, respectively.

NOTE L – COST OF REMOVAL

The Company does not have any material asset retirement obligations arising from legal obligations as defined under Statement on Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). However, under the Company’s current and prior rate plans it has collected through rates an implied cost of removal for its plant assets. This cost of removal collected from customers differs from the FAS 143 definition of an asset retirement obligation in that these collections are for costs to remove an asset when it is no longer deemed usable (i.e. broken or obsolete) and not necessarily from a legal obligation.

New England Power
Notes to Financial Statements

The cost of removal collected from customers has historically been embedded within accumulated depreciation (as these costs have been charged over time through depreciation expense). The Company has reclassified the cost of removal collections to a regulatory liability account to more properly reflect the future usage of these collections. The Company estimates it has collected over time approximately $20 million and $19 million for cost of removal through March 31, 2005 and 2004, respectively.

NOTE M — QUARTERLY INFORMATION (UNAUDITED)


	Quarter Ended			Quarter Ended			Quarter Ended			Quarter Ended
(In thousands)	June 30, 2004			Sept. 30, 2004			Dec. 31, 2004			March 31, 2005

Operating revenue
As previously reported	$	113,919		$	110,983		$	122,120		$	116,150
Adjustment*		1,059	(a)		1,252	(a)		(7,222	)(a)		—

Restated	$	114,978		$	112,235		$	114,898		$	116,150


Operating income
As previously reported	$	18,506		$	18,603		$	24,406		$	25,963
Adjustment*		644	(b)		759	(b)		(4,387	)(b)		—

Restated	$	19,150		$	19,362		$	20,019		$	25,963


Net income
As previously reported	$	17,621		$	16,511		$	21,137		$	24,523
Adjustment*		644	(b)		759	(b)		(4,387	)(b)		—

Restated	$	18,265		$	17,270		$	16,750		$	24,523

New England Power
Notes to Financial Statements


	Quarter Ended			Quarter Ended			Quarter Ended			Quarter Ended
(In thousands)	June 30, 2003			Sept. 30, 2003			Dec. 31, 2003			March 31, 2004

Operating revenue
As previously reported	$	110,629		$	114,235		$	117,208		$	115,739
Adjustment*		547	(a)		746	(a)		690	(a)		4,384	(a)

Restated	$	111,176		$	114,981		$	117,898		$	120,123


Operating income
As previously reported	$	18,935		$	17,986		$	20,269		$	17,614
Adjustment*		332	(b)		453	(b)		419	(b)		2,749	(c)

Restated	$	19,267		$	18,439		$	20,688		$	20,363


Net income
As previously reported	$	18,709		$	18,059		$	18,551		$	17,171
Adjustment*		332	(b)		453	(b)		419	(b)		2,749	(c)

Restated	$	19,041		$	18,512		$	18,970		$	19,920

(a)		Includes amounts related to stranded cost and transmission revenue adjustments.

(b)		Includes amounts related to stranded cost and transmission revenue adjustments and the income tax effect of these amounts.

(c)		Includes amounts related to stranded cost and transmission revenue adjustments and the income tax effect of these amounts and prior period income tax filing true-up adjustments.

*		See Note N “Restatement of Previously Reported Financial Statements” for further discussion on these adjustments.

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

NOTE N — RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS

In connection with the preparation of NEP’s financial statements, management concluded that the Company had understated net income for the fiscal years ended March 31, 2003 and 2004. The following provides a description of the details of the accounting adjustments included in the restatement of the Company’s financial statements and the effect of the adjustments on the Company’s Balance Sheet, Statement of Income, Statement of Retained Earnings, Statement of Comprehensive Income and Statement of Cash Flows for these periods. The restatements reflect accounting errors in recording revenues for the recovery of stranded costs and certain true-ups for expenses relating to federal and state income tax filings were not made timely in fiscal 2003 and 2004. Adjustments related to fiscal year 2001 and 2002 have been reflected as prior period adjustments to retained earnings. The underlying regulatory filings and income tax filings,

New England Power
Notes to Financial Statements

however, were timely and accurately filed.

Details of Accounting Adjustments Included in the Restatement: The accounting adjustments relate primarily to the categories described below. These adjustments affected reported net income and common equity which relate to both the timing and recognition of revenues and expenses and affect the comparison of period-to-period results, as well as business segment reporting.

• Operating revenues: (composed of stranded cost revenues and transmission revenues)

Stranded cost revenues: There were three adjustments recorded during the fiscal year ended March 31, 2005 related to prior periods which affected stranded cost revenues.

(1) In estimating its periodic rate requirements under the CTC, the Company incorrectly calculated the return owed to customers for amounts overcollected. This error resulted in revenue being understated on a pre-tax basis by $3.3 million and $3.5 million for the fiscal years ended March 31, 2003 and 2004, respectively ($2.0 million and $2.1 million after-tax, respectively).

(2) The Company is allowed to earn incentives, referred to as mitigation incentives, for reducing the amount of stranded costs to be charged to customers as compared to the original CTC filings made in 1998. The Company incorrectly recorded these mitigation incentives in the years prior to the year ended March 31, 2005 because it used outdated data. This resulted in an overstatement of pre-tax revenue of $1.7 million pre-tax ($1.0 million after-tax) for the fiscal years ended March 31, 2002 and prior, and an offsetting understatement of revenue of $1.7 million pre-tax ($1.0 million after-tax), for the fiscal year ended March 31, 2004. Certain amounts related to this error correction pertaining to the fiscal quarters ended June 30, 2004 and September 30, 2004 are also being restated and reflected in Note M “Quarterly Information (Unaudited)”.

(3) During fiscal 2004, the Company made a payment to buyout a purchased power contract. The Company is allowed to earn a return on this buyout payment however the Company did not begin recording this return until fiscal 2005. This resulted in an understatement of revenue for the year ended March 31, 2004 of $673,000 pre-tax ($409,000 after-tax). This error was detected and corrected during the fiscal quarter ended December 31, 2004 which has been restated accordingly in Note M “Quarterly Information (Unaudited)”. Certain amounts related to this error correction pertaining to the fiscal quarters ended June 30, 2004 and September 30, 2004 are also being restated and reflected in Note M “Quarterly Information (Unaudited)”.

Transmission revenues: Monthly billings to the Company’s transmission customers are determined

New England Power
Notes to Financial Statements

based on monthly costs incurred to serve those customers, net of certain revenues received during the month. Beginning in the fiscal year ended March 31, 2002, certain revenues related to stranded cost recovery were incorrectly netted against transmission costs as part of the monthly billings to transmission customers. This error was detected and corrected during the fiscal quarter ended December 31, 2004 which has been restated accordingly. This error resulted in revenue to be understated on a pre-tax basis by $941,000 and $463,000 for the fiscal years ended March 31, 2003 and 2004, respectively ($572,000 and $281,000 after-tax, respectively). Certain amounts related to this error correction pertaining to the fiscal quarters ended June 30, 2004 and September 30, 2004 are also being restated and reflected in Note M “Quarterly Information (Unaudited)”.

•Income Taxes: The Company timely filed all state income tax returns and, as a participant in the National Grid General Partnership consolidated return, all federal income tax returns for the periods ending March 22, 2000, March 31, 2000, March 31, 2001, March 31, 2002, and March 31,2003.

In Q4 of 2005, the Company incorrectly recorded the cumulative effect of adjusting the book tax liability to actual tax expense. The Company has corrected this error by recording in each appropriate period the appropriate book tax adjustment.

Additional minimum pension liability: The Company incorrectly reported its additional minimum pension liability (AML) on a gross basis in its balance sheet for the fiscal year ended March 31, 2004. In accordance with FAS 87, for financial statement presentation, the AML should have been combined with the prepaid pension asset. During the preparation of the Form 10-K for the year ended March 31, 2005, it was determined that the presentation of AML in the prior year Form 10-K was incorrect and is therefore being restated.

The Company has set forth below selected restated financial statements for the fiscal years ended March 31, 2003 and 2004. Because certain of the data set forth in the following tables has been restated from amounts previously reported, the following tables reconcile the information presented with those previously reported.

New England Power
Notes to Financial Statements

Statement of Income For the Year Ended March 31, 2003


	Previously						As
(In thousands)	Reported			Adjustments			Restated

Operating revenue, principally from affiliates (Note A)	$	514,006		$	4,242	(a)	$	518,248
Operating expenses:
Purchased electric energy:
Contract termination and nuclear unit shutdown charges		161,583			—			161,583
Other		31,389			—			31,389
Other operation		55,195			—			55,195
Maintenance		22,666			—			22,666
Depreciation and amortization: (Note A)
Amortization of stranded costs		72,394			—			72,394
Other		25,261			—			25,261
Taxes, other than income taxes (Note K)		18,868			—			18,868
Income taxes (Note G)		45,429			2,000	(b)		47,429

Total operating expenses		432,785			2,000			434,785

Operating income		81,221			2,242			83,463
Other income:
Allowance for equity funds used during construction (Note A)		467			—			467
Equity in income of nuclear power companies		4,554			—			4,554
Other income, net		76			—			76

Operating and other income		86,318			2,242			88,560

Interest expense:
Interest on long-term debt		7,694			—			7,694
Other interest		1,231			—			1,231
Allowance for borrowed funds used during construction (Note A)		(34	)		—			(34	)

Total interest		8,891			—			8,891

Net income	$	77,427		$	2,242		$	79,669

(a)		Amount consists of stranded cost and transmission revenue adjustments. See “Operating revenues” item (1) under Stranded cost revenues and Transmission revenues explanations above.

(b)		Amount consists of the income tax effect on the stranded cost and incremental transmission revenue adjustments and income tax filing true ups (see Income taxes explanation above).

New England Power
Notes to Financial Statements

Statement of Comprehensive Income
For the Year Ended March 31, 2003


	Previously					As
(In thousands)	Reported			Adjustments		Restated

Net income	$	77,427		$	2,242	$	79,669
Unrealized gain (loss) on securities, net of tax		(120	)		—		(120	)

Comprehensive income (Note A)	$	77,307		$	2,242	$	79,549

Statement of Retained Earnings
For the Year Ended March 31, 2003


	Previously						As
(In thousands)	Reported			Adjustments			Restated

Retained earnings at beginning of period	$	136,798		$	5,258	(a)	$	142,056
Net income		77,427			2,242			79,669
Dividends declared on cumulative preferred stock		(82	)		—			(82	)
Gain on redemption of preferred stock		11			—			11

Retained earnings at end of period	$	214,154		$	7,500		$	221,654

(a)

Amount includes adjustments for prior periods.

New England Power
Notes to Financial Statements

Statement of Cash Flows
For the Year Ended March 31, 2003


	Previously						As
(In thousands)	Reported			Adjustments			Restated

Operating activities:
Net income	$	77,427		$	2,242		$	79,669
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of stranded costs		72,394						72,394
Other depreciation and amortization		25,261						25,261
Deferred income taxes and investment tax credits, net		2,386			5,738			8,124
Allowance for funds used during construction		(501	)					(501	)
Changes in assets and liabilities:
Increase in accounts receivable, net		(27,901	)		(941	)		(28,842	)
Decrease in regulatory assets		82,827			(3,301	)		79,526
Decrease in prepaid and other current assets		5,680						5,680
Decrease in accounts payable		(4,912	)					(4,912	)
Decrease in purchased power contract obligations		(151,533	)					(151,533	)
Increase in other current liabilities		51,940			(3,738	)		48,202
Decrease in other non-current liabilities		(30,538	)					(30,538	)
Other, net		(639	)					(639	)

Net cash provided by operating activities	$	101,891		$	—		$	101,891

Investing activities:
Proceeds from sale of generating assets, net	$	84,300					$	84,300
Plant expenditures, excluding allowance for funds used during construction		(41,980	)					(41,980	)
Other investing activities		226						226

Net cash provided by investing activities	$	42,546					$	42,546

Financing activities:
Dividends paid on cumulative preferred stock	$	(85	)				$	(85	)
Preferred stock – retirements		(141	)					(141	)

Net cash used in financing activities	$	(226	)				$	(226	)

Net increase in cash and cash equivalents	$	144,211					$	144,211
Cash and cash equivalents at beginning of period	$	103,467					$	103,467

Cash and cash equivalents at end of period	$	247,678					$	247,678

New England Power
Notes to Financial Statements

Statement of Income
For the Year Ended March 31, 2004


	Previously
(In thousands)	Reported			Adjustments			As Restated

Operating revenue, principally from affiliates (Note A)	$	457,811		$	6,367	(a)	$	464,178
Operating expenses:
Purchased electric energy:
Contract termination and nuclear unit shutdown charges		145,517			—			145,517
Other		14,387			—			14,387
Other operation		60,317			—			60,317
Maintenance		14,498			—			14,498
Depreciation and amortization: (Note A)
Amortization of stranded costs		70,710			—			70,710
Other		18,011			—			18,011
Taxes, other than income taxes (Note K)		16,957			—			16,957
Income taxes (Note G)		42,610			2,414	(b)		45,024

Total operating expenses		383,007			2,414			385,421

Operating income		74,804			3,953			78,757
Other income:
Allowance for equity funds used during construction (Note A)		680			—			680
Equity in income of nuclear power companies		1,675			—			1,675
Other income, net		2,533			—			2,533

Operating and other income		79,692			3,953			83,645

Interest expense:
Interest on long-term debt		5,875			—			5,875
Other interest		1,363			—			1,363
Allowance for borrowed funds used during construction (Note A)		(36	)		—			(36	)

Total interest		7,202			—			7,202

Net income	$	72,490		$	3,953		$	76,443

(a)		Amount consists of stranded cost and transmission revenue adjustments. See Stranded cost revenues and Transmission revenues explanations under “Operating revenues” above.

(b)		Amount consists of the income tax effect on the stranded cost and transmission revenue adjustments and income tax filing true-ups (see Income taxes explanation above).

New England Power
Notes to Financial Statements

Statement of Comprehensive Income
At March 31, 2004


	Previously
(In thousands)	Reported		Adjustments		As Restated

Net income	$	72,490	$	3,953	$	76,443
Unrealized gain (loss) on securities, net of tax		317		—		317

Comprehensive income (Note A)	$	72,807	$	3,953	$	76,760

Statement of Retained Earnings
At March 31, 2004


	Previously
(In thousands)	Reported			Adjustments		As Restated

Retained earnings at beginning of period	$	214,154		$	7,500	$	221,654
Net income		72,490			3,953		76,443
Dividends declared on cumulative preferred stock		(75	)		—		(75	)
Dividends declared on common stock		(77,250	)		—		(77,250	)

Retained earnings at end of period	$	209,319		$	11,453	$	220,772

New England Power
Notes to Financial Statements

Balance Sheet
At March 31, 2004

Previously

(In thousands)

Reported

Adjustments

Restated

Assets

Utility plant, at original cost (Note A)

878,824

878,824

Less accumulated provisions for depreciation and amortization

240,203

240,203

638,621

638,621

Construction work in progress

12,852

12,852

Net utility plant

651,473

651,473

Goodwill (Note A)

338,188

338,188

Investments:

Equity investments in nuclear power companies (Note C)

18,305

18,305

Nonutility property and other investments

11,290

11,290

Total investments

29,595

29,595

Current assets:

Cash and cash equivalents (including $229,400 and $224,150 with affiliates)

229,716

229,716

Accounts receivable:

Affiliated companies

51,131

1,738

(a)

52,869

Others (less reserves of $153 and $153)

104,338

104,338

Fuel, materials and supplies, at average cost

2,054

2,054

Prepaid and other current assets

1,370

1,370

Deferred federal and state income taxes

202

202

Regulatory assets – purchased power obligations

105,011

105,011

Total current assets

493,822

1,738

495,560

Regulatory assets (Note B)

1,134,382

8,971

(b)

1,143,353

Additional minimum pension liability regulatory asset (Note B)

62,454

62,454

Prepaid pension asset

47,245

(39,952

) (c)

7,293

Deferred charges and other assets

5,374

5,374

Total assets

2,762,533

(29,243

)

2,773,290

(a)		Amount consists of transmission revenue adjustments. See Transmission revenues explanation under “Operating revenues” above.

(b)		Amount consists of stranded cost revenue adjustments. See items (1) and (2) in Stranded cost revenues explanation under “Operating revenues” above.

(c)		Amount consists of additional minimum pension liability adjustments. See “Additional minimum pension liability” explanation above.

New England Power
Notes to Financial Statements

Balance Sheet continued
At March 31, 2004


	Previously					As
(In thousands)	Reported		Adjustments			Restated

Capitalization and Liabilities
Capitalization:
Common stock, par value $20 per share,
Authorized – 6,449,896 shares
Outstanding – 3,619,896 shares	$	72,398				$	72,398
Other paid-in capital		731,974					731,974
Retained earnings		209,319		11,453			220,772
Accumulated other comprehensive income (Note A)		87					87

Total common equity		1,013,778		11,453			1,025,231
Cumulative preferred stock, par value $100 per share (Note I)		1,274					1,274
Long-term debt (Note E)		410,297					410,297

Total capitalization		1,425,349		11,453			1,436,802

Current liabilities:
Accounts payable (including $34,814 and $22,798 to affiliates)		59,620					59,620
Accrued liabilities:
Taxes		18,337		(11,595	)(d)		6,742
Interest		532					532
Purchased power obligations		105,011					105,011
Other accrued expenses		3,216					3,216
Dividends payable		19					19

Total current liabilities		186,735		(11,595	)		175,140

Deferred federal and state income taxes		234,054		11,524	(d)		245,578
Unamortized investment tax credits		7,885					7,885
Accrued Yankee nuclear plant costs (Note D)		269,997					269,997
Purchased power obligations		293,296					293,296
Additional minimum pension liability		39,952		(39,952	)(f)		0
Other reserves and deferred credits		305,265		(673	)(e)		304,592
Commitments and contingencies (Note D)

Total capitalization and liabilities	$	2,762,533		(29,243	)	$	2,733,290

(d)		Amounts consist of income tax effects of the stranded cost and transmission revenue adjustments and income tax filing true ups. See Details of Accounting Adjustments above.

(e)		Amount consists of stranded cost revenue adjustments. See item (3) in Stranded cost revenues explanation under Operating revenues above.

(f)		Amount consists of additional minimum pension liability adjustments. See “Additional minimum pension liability” explanation above.

New England Power
Notes to Financial Statements

Statement of Cash Flows
At March 31, 2004


	Previously						As
(In thousands)	Reported			Adjustments			Restated

Operating activities:
Net income	$	72,490		$	3,953		$	76,443
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of stranded costs		70,710						70,710
Other depreciation and amortization		18,011						18,011
Deferred income taxes and investment tax credits, net		(23,064	)		(3,217	)		(26,281	)
Allowance for funds used during construction		(716	)					(716	)
Changes in assets and liabilities:
Increase in accounts receivable, net		(18,700	)		(463	)		(19,163	)
Decrease in regulatory assets		177,228			(5,230	)		171,998
Increase in prepaid and other current assets		(1,514	)					(1,514	)
Decrease in accounts payable		(6,936	)					(6,936	)
Decrease in purchased power contract obligations		(111,620	)					(111,620	)
Decrease in other current liabilities		(45,568	)		5,630			(39,938	)
Decrease in other non-current liabilities		(55,578	)		(673	)		(56,251	)
Other, net		9,775						9,775

Net cash provided by operating activities	$	84,518		$	—		$	84,518

Investing activities:
Return of capital from equity investment	$	11,977					$	11,977
Plant expenditures, excluding allowance for funds used during construction		(41,318	)					(41,318	)
Other investing activities		4,207						4,207

Net cash used in investing activities	$	(25,134	)				$	(25,134	)

Financing activities:
Dividends paid on common stock	$	(77,250	)				$	(77,250	)
Dividends paid on cumulative preferred stock		(75	)					(75	)
Preferred stock – retirements		(21	)					(21	)

Net cash used in financing activities	$	(77,346	)				$	(77,346	)

Net decrease in cash and cash equivalents	$	(17,962	)				$	(17,962	)
Cash and cash equivalents at beginning of period	$	247,678					$	247,678

Cash and cash equivalents at end of period	$	229,716					$	229,716

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

The Company has nothing to report for this item.

ITEM 9A. CONTROLS AND PROCEDURES

The Company has carried out an evaluation under the supervision and with the participation of its management, including the Chief Financial Officer and President, of the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives. Based on and as of that evaluation, it was determined that these disclosure controls and procedures were not effective, due to the material weakness described below, in providing reasonable assurance that information required to be disclosed in reports that the Company files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required.

The Company identified accounting errors in that certain true-ups for revenues relating to regulatory filings for the recovery of stranded costs and certain true-ups for expenses relating to federal and state income tax filings were not made timely in fiscal 2001, 2002, 2003 and 2004. In addition, some amounts recorded for revenue in fiscal 2004 were calculated incorrectly, and the corrections were recorded during the fiscal quarter ended December 31, 2004. As a result, the Company restated its previously issued financial statements contained in this Form 10-K. The Company evaluated whether the misstatements in prior periods were caused by a material weakness in its internal controls over true-ups of estimates. A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the financial statements will not be prevented or detected. The Company concluded that the control deficiency that resulted in the understatement of revenue and overstatement of income tax expense constitutes a material weakness. Specifically, the Company did not analyze and true-up estimated stranded cost revenues and estimated income taxes to the actual filings on a timely basis. To address this material weakness, the Company has established a formal written policy requiring that true-ups and analysis of estimated stranded cost revenues and income tax expense be recorded on a timely basis. In addition, the Company has updated its procedures to require that the relevant managers confirm that true-ups and analysis are being recorded on a timely basis.

The changes described above were made after the fourth fiscal quarter. During that quarter there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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


Name	Age		Position
Stephen P. Lewis		48	President and Director
John G. Cochrane		47	Chief Financial Officer, Vice President and Director
Michael Calviou		36	Vice President
Edward A. Capomacchio		59	Controller
Marc F. Mahoney		51	Vice President
Michael E. Jesanis		48	Vice President and Director
Lawrence J. Reilly		49	Vice President and Director
James S. Robinson		52	Vice President and Treasurer
Herb Schrayshuen		51	Vice President
Jeffrey A. Scott		50	Senior Vice President, Transmission, of National Grid USA and Director

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 successor is elected and qualified. There are no family relationships between any of the directors and the executive officers listed in the table.

Mr. Lewis was elected President and director effective April 16, 2003; he was Vice President from February 26, 2003 until April 16, 2003. 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 Transco. From 1997 to 2001, he was a Network Manager for Services for National Grid Transco.

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, Senior Vice President since May 2002 and Treasurer since April 2003 and has served as Treasurer of National Grid USA Service Company since May 2003. From 1998 to 2002, he was Treasurer of National Grid USA (and its predecessor, New England Electric System) and of National Grid USA Service Company.

Mr. Calviou was elected Vice President effective May 1, 2004. He previously worked in National Grid Transco’s UK Transmission business, most recently as Commercial Frameworks Manager from February 2003 to April 2004, and prior to that as Strategy and Development Manager from December 2001 to February 2003, and as Strategy and Portfolio Manager from March 2000 to December 2001.

Mr. Capomacchio has served as Controller of the Company and its New England retail affiliates 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. 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. Jesanis has been Vice President since March 17, 1998 and was elected director in 2000. He became President of National Grid USA in November 2003 having been its Chief Operating Officer and responsible for the day-to-day operations since January 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. Mr. Jesanis is also a director of National Grid USA and of Niagara Mohawk Power Corporation and was appointed a director of National Grid Transco in July 2004.

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.

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. Scott was elected director July 1, 2003. He has been a Senior Vice President and director of National Grid USA since August 1, 2003. He joined The National Grid Company in 1990, becoming Commercial Director of UK Transmission in February 2003. Currently, he is responsible for all operations associated with National Grid’s Transco’s US Transmission business.

ITEM 11. EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth the compensation paid or accrued for services rendered to NEP in the fiscal years ended March 31, 2005, 2004 and 2003 by the president and the sole executive officer whose compensation allocable to NEP exceeded $100,000 and who was serving as an executive officer on March 31, 2005 (the “Named Executive Officers”).


									Long-Term
			Annual Compensation (b)						Compensation
							Other		Awards		All Other
							Annual		Securities		Compen-
Name and Principal							Compen-		Underlying		sation($)(b)(
Position (a)	Year		Salary($)		Bonus($)		sation($)(c)		Options (#)		d)
Stephen P. Lewis		2005		79,540		11,932		9,448		0		106,348
President		2004		47,183		10,282		23,245		0		118,476
		2003		—		—		—		—		—

Jeff Scott		2005		89,994		21,599		16,276		0		89,044
Senior Vice President,		2004		69,190		17,298		12,482		0		38,053
Transmission, National Grid USA		2003		—		—		—		—		—

(a)		Messrs. Lewis and Scott perform services for affiliate companies. Compensation that is allocable to NEP is set forth in the table.

(b)		Messrs. Lewis and Scott are on assignment to the US from the UK, and they are paid in pounds sterling. A conversion rate of $1.87/£1.00 was used to translate their compensation, which is the weighted average exchange rate for the National Grid companies’ results for the fiscal year ended March 31, 2005.

(c)		Includes employer contribution to pension plan and cost of living adjustments. Also, for Mr. Scott, includes the value of shares granted under the Share Matching Plan on the date of the grant.

(d)		Includes payments associated with the executive’s overseas assignment.

Long-Term Incentive Plans – Awards in Last Fiscal Year

The following table sets forth awards made under the National Grid Transco Performance Share Plan (the PSP) to the Named Executive Officers during fiscal 2005.

Estimated Future Payouts

Threshold

Maximum

Name

Number of Shares (#)

Performance Period

(#)

Stephen P. Lewis

6,006

July 1, 2004 through June 30, 2007

1,802

6,006

Jeff Scott

22,653

July 1, 2004 through June 30, 2007

6,796

22,653

Under the PSP, the Named Executive Officers and certain members of management are awarded notional allocations of ordinary shares of National Grid Transco. Shares vest after three years, subject to the satisfaction of the relevant performance criterion, which is set at the date of grant. Shares must then be held for a further year, after which they are released. For the grants set forth above, the relevant criterion is total shareholder return (TSR) performance over a three-year period, relative to the TSR performances of a group of comparator companies. This comparator group includes companies in the energy sector, against which National Grid Transco benchmarks its performance for business purposes, and other utilities based in the UK, Europe and the US. The proportion of the original award of shares that will transfer to participants will depend on National Grid Transco’s performance when compared to the comparator group. National Grid Transco must achieve median ranking in order for participants to realize the threshold payout of 30% of the original award. It must rank in the upper quartile relative to the comparator group to achieve the maximum payout of 100% of the original award.

Option Exercises in Fiscal Year 2005 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 2005, 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.


					Number of Shares Underlying
	Options		Value		Unexercised Options on				Value of Unexercised Options
	Exercised		Realized		March 31, 2005				on March 31, 2005 (a) (b)
Name	(#)		($)		Exercisable		Unexercisable		Exercisable		Unexercisable
Stephen P. Lewis		0		0		7,701		8,147	$	0	$	4,497
Jeff Scott		0		0		54,024		30,114	$	54,609	$	4,848

(a)		Calculated based on the March 31, 2005 closing price of National Grid Transco ordinary shares on the London Stock Exchange (£4.9025). That price exceeded the exercise price for some of the stock option grants, but not all of them.

(b)		A conversion rate of $1.84/£1.00 was used to translate the option value, which is the exchange rate for the National Grid companies’ balance sheets at March 31, 2005.

Pension Plans

Stephen Lewis and Jeff Scott participate in the National Grid Company Group of the Electricity Supply Pension Scheme. Within the pension plan only base salary is pensionable.

The normal retirement age for Stephen Lewis is 63 years of age. Mr. Lewis’s pension at normal retirement age within the pension plan is calculated as 1/80^th of final salary for each year of service, as shown in the table below, plus a lump sum of three times his annual pension. These are the standard benefits available under the pension plan.

Pension Table – Standard Benefit for Mr. Lewis:


Final	Annual Annuity Value Based on Years of Service
Compensation	20		25		30		35		40		45
$140,250	$	35,063	$	43,829	$	52,594	$	61,360	$	70,125	$	78,892
$187,000	$	46,750	$	58,438	$	70,125	$	81,813	$	93,500	$	105,188
$233,750	$	58,438	$	73,048	$	87,656	$	102,267	$	116,875	$	131,485
$280,500	$	70,125	$	87,656	$	105,188	$	122,719	$	140,250	$	157,781
$327,250	$	81,813	$	102,267	$	122,719	$	143,173	$	163,625	$	184,079
$374,000	$	93,500	$	116,875	$	140,250	$	163,625	$	187,000	$	210,375
$420,750	$	105,188	$	131,485	$	157,781	$	184,079	$	210,375	$	236,673
$467,500	$	116,875	$	146,094	$	175,313	$	204,531	$	233,750	$	262,969
$561,000	$	140,250	$	175,313	$	210,375	$	245,438	$	280,500	$	315,563

Mr. Lewis has 32 years of service.

Jeff Scott is entitled to standard benefits under the pension plan for service up to 1 December 1994. For service after 1 December 1994 he is eligible to participate under the executive arrangements of the pension plan. The provisions of the executive arrangements are designed to give a pension of two-thirds of final salary (including the pension equivalent of the lump sum from the standard benefits), subject to completion of 20 years’ service and including any pension rights earned in previous employments, at age 60.

Pension Table – Executive Provision for Mr. Scott:


Final	Annual Annuity Value Based on Years of Service
Compensation	20		25		30		35		40		45
$140,250	$	35,227	$	47,749	$	60,272	$	72,795	$	85,317	$	97,838
$187,000	$	46,971	$	63,664	$	80,363	$	97,060	$	113,756	$	130,451
$233,750	$	58,712	$	79,582	$	100,455	$	121,326	$	142,195	$	163,064
$280,500	$	70,456	$	95,497	$	120,546	$	145,589	$	170,634	$	195,677
$327,250	$	82,198	$	111,415	$	140,635	$	169,854	$	199,073	$	228,290
$374,000	$	93,941	$	127,330	$	160,727	$	194,119	$	227,512	$	260,901
$420,750	$	105,683	$	143,246	$	180,818	$	218,384	$	255,951	$	293,513
$467,500	$	117,427	$	159,163	$	200,909	$	242,649	$	284,390	$	326,126
$561,000	$	140,912	$	190,994	$	241,090	$	291,180	$	341,269	$	391,352

Mr. Scott has 30 years of service.

A spouse’s pension is payable on the death in service equal to two-thirds of the pension had service been continued to normal retirement age. On death in retirement, a spouse’s pension is payable equal to two-thirds of the pension prior to any exchange for a cash lump sum at retirement. Once payments from the pension have begun, pensions are increased annually in line with price inflation up to a maximum of 5%.

Dollar amounts in the pension tables are translated from pounds sterling at the rate of $1.87 per £1.00.

Employment Contracts, Termination of Employment and Change-in-Control Arrangements

Messrs. Lewis and Scott both have employment contracts in relation to their assignments to the US from the UK. The contracts set forth salary and bonus, along with certain allowances, benefits and accommodations in relation to working overseas. There are no termination or change-in-control arrangements for these executive officers.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDERS MATTERS

The following table sets forth the number of ordinary shares of National Grid Transco beneficially owned as of June 1, 2005 by: (a) each of the Named Executive Officers; (b) each director of the Company; 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.


Name	Number of Shares
	Beneficially Owned*
Stephen P. Lewis		9,868
Jeffrey A. Scott		109,966
John G. Cochrane		96,060
Michael E. Jesanis		147,515
Lawrence J. Reilly (a)		139,401
All directors and executive officers as a group (11 persons) (a)		645,884

*		This number is expressed in terms of ordinary shares. It includes American Depositary Receipts listed on the New York Stock Exchange, each of which represents five ordinary shares

(a)		Includes shares held by Mr. Reilly’s spouse and Mr. Calviou’s spouse.

None.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

PricewaterhouseCoopers LLP, an independent registered public accounting firm, served as auditors of the Company for the fiscal year ended March 31, 2005.

Audit Fees

The aggregate fees billed by PricewaterhouseCoopers LLP for the audit of the Company’s financial statements and regulatory filings for the fiscal year ended March 31, 2005, and the reviews of quarterly reports on Form 10-Q filed during the fiscal year ended March 31, 2005 were $198,146. The aggregate fees billed by PricewaterhouseCoopers LLP for the audit of the Company’s financial statements and regulatory filings for the fiscal year ended March 31, 2004, and the reviews of quarterly reports on Form 10-Q filed during the fiscal year ended March 31, 2004 were $91,187.

Audit-Related Fees, Tax Fees and All Other Fees

The Company did not pay any other type of fee and did not receive any other services from PricewaterhouseCoopers LLP during the fiscal years ended March 31, 2005 and March 31, 2004.

The Company’s stockholders appoint the Company’s independent auditors, with the approval of the Audit Committee of the Company’s indirect parent company, National Grid Transco plc. Subject to National Grid Transco’s Articles of Association, the Audit Committee is solely and directly responsible

for the approval of the appointment, re-appointment, compensation and oversight of the Company’s independent auditors. The Audit Committee must approve in advance all non-audit work to be performed by the independent auditors.

During the fiscal year ended March 31, 2005, all of the services provided by PricewaterhouseCoopers LLP to the Company were pre-approved by the Audit Committee.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Financial Statement Schedules

	•		Report of Independent Registered Public Accounting Firm

	•		Statement of Income, Statement of Retained Earnings and Statements of Comprehensive Income for the fiscal years ended March 31, 2005, 2004 and 2003

	•		Balance Sheets at March 31, 2005 and 2004

	•		Statements of Cash Flows for fiscal years ended March 31, 2005, 2004 and 2003

	•		Notes to Financial Statements

Exhibits

The exhibit index is incorporated herein by reference.

SIGNATURES

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.


	NEW ENGLAND POWER COMPANY
Date: July 14, 2005	By:	/s/ Stephen P. Lewis
		Stephen P. Lewis
		President

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, this report has been signed below on July 14, 2005 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.


Signature		Title
/s/ Stephen P. Lewis
Stephen P. Lewis		President and Director (Principal Executive Officer)

/s/ John G. Cochrane
John G. Cochrane		Vice President and Chief Financial Officer and Director (Principal Financial Officer)

/s/ Edward A. Capomacchio
Edward A. Capomacchio		Controller (Principal Accounting Officer)

/s/ Michael E. Jesanis
Michael E. Jesanis		Director

/s/ Lawrence J. Reilly
Lawrence J. Reilly		Director

/s/ Jeffrey A. Scott
Jeffrey A. Scott		Director

EXHIBIT INDEX

Note: Exhibits marked with “*” are incorporated by reference as indicated.


Exhibit
No.		Description
3.1*		Articles of Organization as amended through June 25, 1987 (Exhibit 3(a) to 1988 Form 10-K, File No. 0-1229); Articles of Amendment dated January 27, 1998 (Exhibit B.18.a to National Grid USA 1999 Form U-5-S, File No. 30-33); Articles of Amendment dated February 25, 2000 (Exhibit 3(a) to 2000 Form 10-K, File No. 1-6564); Articles of Merger dated May 1, 2000 (Exhibit 3(a) to 2001 Form 10-K, File No. 1-6564)

3.2*		By-laws of the Company as amended February 20, 2003 (Exhibit 3.2 to Form 10-K for fiscal year ended March 31, 2003, File No. 2-26651)

10.1*		Boston Edison Company et al. and the Company: Amended REMVEC Agreement dated August 12, 1977 (Exhibit 5-4(d), File No. 2-61881)

10.2*		Boston Edison Company et al. and the Company: REMVEC II Agreement dated on or about July 1, 1994 (Exhibit 10(a)(I) to NEES 1997 Form 10- K, File No. 1-3446)

10.3*		Boston Edison Company et al. and the Company: Security Analysis Services Agreement dated on or about July 1, 1994 (Exhibit 10(a)(ii) to NEES 1997 Form 10-K, File No. 1-3446)

10.4*		Connecticut Yankee Atomic Power Company et al. and the Company: Stockholders Agreement dated July 1, 1964 (Exhibit 13-9-A, File No. 2-2006); Power Purchase Contract dated July 1, 1964 (Exhibit 13-9-B, File No. 2-23006); Additional Power Contract dated as of April 30, 1984 and 1996; Amendatory Agreement dated as of December 4, 1996 (Exhibit 10(c) to 1996 Form 10-K, File No. 1-3446); Supplementary Power Contract dated as of April 1, 1987 (Exhibit 10(c) to 1987 Form 10-K, File No. 0-1229); Capital Funds Agreement dated September 1, 1964 (Exhibit 13-9-C, File No. 2-23006); Transmission Agreement dated October 1, 1964 (Exhibit 13-9-D, File No. 2-23006); Agreement revising Transmission Agreement dated July 1, 1979 (Exhibit to NEES 1979 Form 10-K, File No. 1-3446); Amendment revising Transmission Agreement dated as of January 19, 1994 (Exhibit 10(c) to NEES 1995 Form 10-K, File No. 1-3446); Five Year Capital Contribution Agreement dated November 1, 1980 (Exhibit 10(e) to NEES 1980 Form 10-K, File No. 1-3446)


Exhibit
No.		Description
10.5*		Maine Yankee Atomic Power Company et al. and the Company: Capital Funds Agreement dated May 20, 1968 and Power Purchase Contract dated May 20, 1968 (Exhibit 4-5, File No. 2-29145); Amendments dated as of January 1, 1984, March 1, 1984 (Exhibit 10(d) to NEES 1983 Form 10-K, File No. 1-3446); October 1, 1984, and August 1, 1985 (Exhibit 10(d) to NEES 1985 Form 10-K, File No. 1-3446); Stockholders Agreement dated May 20, 1968 (Exhibit 10-20; File No. 2-34267); Additional Power Contract dated as of February 1, 1984 (Exhibit 10(d) to NEES 1985 Form 10-K, File No. 1-3446); 1997 Amendatory Agreement dated as of August 6, 1997 (Exhibit 10(d) to NEES 1997 Form 10-K, File No. 1-3446)

10.6*		New England Electric Transmission Corporation et al. and the Company: Phase I Terminal Facility Support Agreement dated as of December 1, 1981 (Exhibit 10(g) to NEES 1981 Form 10-K, File No. 1-3446); Amendments dated as of June 1, 1982 and November 1, 1982 (Exhibit 10(f) to NEES 1982 Form 10-K, File No. 1-3446); Agreement with respect to Use of the Quebec Interconnection dated as of December 1, 1981 (Exhibit 10(g) to NEES 1981 Form 10-K, File No. 1-3446); Amendments dated as of May 1, 1982 and November 1, 1982 (Exhibit 10(f) to NEES 1982 Form 10-K, File No. 1-3446); Amendment dated as of January 1, 1986 (Exhibit 10(f) to NEES 1986 Form 10-K, File No. 1-3446); Agreement for Reinforcement and Improvement of the Company’s Transmission System dated as of April 1, 1983 (Exhibit 10(f) to NEES 1983 Form 10-K, File No. 1-3446); Lease dated as of May 16, 1983 (Exhibit 10(f) to NEES 1983 Form 10-K, File No. 1-3446); Upper Development-Lower Development Transmission Line Support Agreement dated as of May 16, 1983 (Exhibit 10(f) to NEES 1983 Form 10-K, File No. 1-3446); Agreement with Respect to Second Amendment and Restatement of Agreement with Respect to Use of Quebec Interconnection dated November 19, 1997 (Exhibit 10(d) to 2002 Form 10-K, File No. 1-6564)

10.7*		Vermont Electric Transmission Company, Inc. et al. and the Company: Phase I Vermont Transmission Line Support Agreement dated as of December 1, 1981; Amendments dated as of June 1, 1982 and November 1, 1982 (Exhibit 10(g) to NEES 1982 Form 10-K, File No. 1-3446); Amendment dated as of January 1, 1986 (Exhibit 10(h) to NEES 1986 Form 10-K, File No. 1-3446)

10.8*		New England Power Pool Agreement: Restated New England Power Pool Agreement as amended through the Seventy-Sixth Agreement amending New England Power Pool Agreement and Amendments dated as of July 13, 2001, September 24, 2001, October 12, 2001, December 7, 2001, and January 18, 2002 (Exhibit 10(f) to 2002 Form 10-K, File No. 1-6564)


Exhibit No.
10.9*		Vermont Yankee Nuclear Power Corporation et al. and the Company: Capital Funds Agreement dated February 1, 1968, Amendment dated March 12, 1968 and Power Purchase Contract dated February 1, 1968 (Exhibit 4-6, File No. 2-29145); Amendments dated as of June 1, 1972, April 15, 1983 (Exhibit 10(k) to NEES 1983 Form 10-K, File No. 0-1229) and April 24, 1985 (Exhibit 10(n) to NEES 1985 Form 10-K, File No. 1-3446); Amendment dated as of June 1, 1985 (Exhibit 10(n) to 1988 Form 10-K, File No. 0-1229); Amendments dated May 6, 1988 (Exhibit 10(n) to 1988 Form 10-K, File No.0-1229); Amendment dated as of June 15, 1989 (Exhibit 10(k) to 1989 NEES Form 10-K, File No. 1-3446); Additional Power Contract dated as of February 1, 1984 (Exhibit 10(k) to NEES 1983 Form 10-K, File No. 1-3446); Guarantee Agreement dated as of November 5, 1981 (Exhibit 10(j) to NEES 1981 Form 10-K, File No. 1-3446)

10.9(a)		2001 Amendatory Agreement dated as of September 21, 2001 between Vermont Yankee Nuclear Power Corporation and New England Power Company.

10.10*		Yankee Atomic Electric Company et al. and the Company:
		Amended and Restated Power Contract dated April 1, 1985 (Exhibit 10(l) to NEES 1985 Form 10-K, File No. 1-3446); Amendment dated May 6, 1988 (Exhibit 10(l) to NEES 1988 Form 10-K, File No. 1-3446); Amendments dated as of June 26, 1989 and July 1, 1989 (Exhibit 10(l) to 1989 NEES Form 10-K, File No. 1-3446); Amendment dated as of February 1, 1992 (Exhibit 10(l) to 1992 NEES Form 10-K, File No. 1-3446)

10.11*		New England Hydro-Transmission Electric Company, Inc. et al. and the Company: Phase II Massachusetts Transmission Facilities Support Agreement dated as of June 1, 1985 (Exhibit 10(t) to NEES 1986 Form 10-K, File No. 1-3446); Amendment dated as of May 1, 1986 (Exhibit 10(t) to NEES 1986 Form 10-K, File No. 1-3446); Amendments dated as of February 1, 1987, June 1, 1987, September 1, 1987, and October 1, 1987 (Exhibit 10(u) to NEES 1987 Form 10-K, File No. 1-3446); Amendment dated as of August 1, 1988 (Exhibit 10(u) to NEES 1988 Form 10-K, File No.1-3446); Amendment dated January 1, 1989 (Exhibit 10(u) to NEES 1990 Form 10-K, File No. 1-3446)

10.12*		New England Hydro-Transmission Corporation et al. and the Company: Phase II New Hampshire Transmission Facilities Support Agreement dated as of June 1, 1985 (Exhibit 10(u) to NEES 1986 Form 10-K, File No. 1-3446); Amendment dated as of May 1, 1986 (Exhibit 10(u) to NEES 1986 Form 10-K, File No. 1-3446); Amendments dated as of February 1, 1987, June 1, 1987, September 1, 1987, and October 1, 1987 (Exhibit 10(v) to NEES 1987 Form 10-K, File No. 1-3446).Amendment dated as of August 1, 1988 (Exhibit 10(v) to NEES 1988 Form 10-K, File No. 1-3446); Amendments dated January 1, 1989 and January 1, 1990 (Exhibit 10(v) to NEES 1990 Form 10-K, File No. 1-3446)


Exhibit No.
10.13*		Vermont Electric Power Company et al. and the Company: Phase II New England Power AC Facilities Support Agreement dated as of June 1, 1985 (Exhibit 10(v) to NEES 1986 Form 10-K, File No. 1-3446); Amendment dated as of May 1, 1986 (Exhibit 10(v) to NEES 1986 Form 10-K, File No. 1-3446). Amendments dated as of February 1, 1987, June 1, 1987, and September 1, 1987 (Exhibit 10(w) to NEES 1987 Form 10-K, File No. 1-3446); Amendment dated as of August 1, 1988 (Exhibit 10(w) to NEES 1988 Form 10-K, File No. 1-3446)

10.14*		Severance Protection Agreement between New England Electric System and John G. Cochrane dated March 1, 1998 (substantially in the form of the Severance Protection Agreement Exhibit 10(y) to New England Electric System 10-K for fiscal year ended December 31, 1998, file no. 1-3446)

		Amendment to Severance Protection Agreement dated December 9, 1998 (Exhibit 10(i) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

		Amendment to Severance Protection Agreement dated March 15, 2003 (Exhibit 10(i) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

		Amendment to Severance Protection Agreement dated September 1, 2003 (Exhibit 10(i) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

10.15*		Service Agreement among National Grid Transco plc, National Grid USA and Michael E. Jesanis dated July 8, 2004 (Exhibit 4.5 to National Grid Transco plc Form 20-F for fiscal year ended March 31, 2005, file no. 1-14958).

10.16		Letter of Appointment between National Grid Transco plc and Stephen Lewis dated October 28, 2002 (filed herewith)

		Temporary International Assignment Contract among The National Grid Group plc, The National Grid Company and Stephen Lewis dated October 21, 2003 (filed herewith)

10.17*		Severance Protection Agreement between New England Electric System and Lawrence J. Reilly dated February 25, 1997 (substantially in the form of the Severance Protection Agreement Exhibit 10(y) to New England Electric System 10-K for fiscal year ended December 31, 1998, file no. 1-3446)


Exhibit
No.		Description
		Amendment to Severance Protection Agreement dated December 9, 1998 (Exhibit 10(l) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

		Amendment to Severance Protection Agreement dated March 15, 2003 (Exhibit 10(l) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

10.18*		Contract of Employment between The National Grid Company plc and Jeffrey A. Scott dated November 30, 1994 (Exhibit 10(m) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

		Letter of Appointment between National Grid Transco plc and Jeffrey A. Scott dated June 5, 2003 (Exhibit 10(m) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

		Temporary International Assignment Contract among The National Grid Group plc, The National Grid Company plc and Jeffrey A. Scott dated June 3, 2003 (Exhibit 10(m) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

10.19*		National Grid USA Companies’ Deferred Compensation Plan Amended and Restated December 6, 2001 (Exhibit 10(l) to New England Power Company 10-K for fiscal year ended March 31, 2002, file no. 2-26651)

		Amendment to National Grid USA Companies’ Deferred Compensation Plan dated April 1, 2002 (Exhibit 10(n) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

		Amendment to National Grid USA Companies’ Deferred Compensation Plan dated September 1, 2003 (Exhibit 10(n) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

10.20*		National Grid USA Companies’ Executive Severance Plan Amended and Restated March 1, 2003 (Exhibit 10(o) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

		Amendment to National Grid USA Companies’ Executive Severance Plan dated September 1, 2003 (Exhibit 10(o) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)


Exhibit
No.		Description
10.21*		National Grid USA Companies’ Executive Supplemental Retirement Plan Revised and Restated December 21, 2001 (Exhibit 10(n) to New England Power Company 10-K for fiscal year ended March 31, 2002, file no. 2-26651)

		Amendment to National Grid USA Companies’ Executive Supplemental Retirement Plan dated February 1, 2002 (Exhibit 10(p) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

		Amendment to National Grid USA Companies’ Executive Supplemental Retirement Plan dated August 1, 2003 (Exhibit 10(p) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

		Amendment to National Grid USA Companies’ Executive Supplemental Retirement Plan dated September 1, 2003 (Exhibit 10(p) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

10.22*		New England Electric Companies’ Executive Retirees Health and Life Insurance Plan as Amended and Restated January 1, 1996 (Exhibit 10(o) to New England Electric System 10-K for fiscal year ended December 31, 1997, file no. 1-3446)

10.23*		National Grid USA Companies’ Incentive Compensation Plan as Amended and Restated March 1, 2003 (Exhibit 10(r) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

		Amendment to National Grid USA Companies’ Incentive Compensation Plan dated September 1, 2003 (Exhibit 10(r) to Niagara Mohawk Power Corporation 10-K for fiscal year ended March 31, 2005, file no. 1-2987)

10.24*		National Grid USA Companies’ Retirement Supplement Plan Revised and Restated December 21, 2001 (Exhibit 10(m) to New England Power Company 10-K for fiscal year ended March 31, 2002, file no. 2-26651)

10.25*		National Grid Transco Performance Share Plan 2002 (as approved July 23, 2002 by a resolution of the shareholders of National Grid Group plc, adopted October 17, 2002 by a resolution of the Board of National Grid Group plc, amended June 26, 2003 by the Share Schemes Sub-Committee of National Grid Transco plc, and amended May 5, 2004 by the Share Schemes Sub-Committee of National Grid Transco plc) (Exhibit 4.19 of National Grid Transco Form 20-F for fiscal year ended March 31, 2004, file no. 1-14958)


Exhibit
No.		Description
10.26*		National Grid Executive Share Option Plan 2002 (Exhibit 4(c) to National Grid Group Form 20-F for fiscal year ended March 31, 2002, file no. 1-14958)

10.27*		National Grid Group Share Matching Plan 2002 (Exhibit 4(c) to National Grid Group Form 20-F for fiscal year ended March 31, 2002, file no. 1-14958)

10.28*		National Grid Executive Share Option Plan 2000 (Exhibit 4C to National Grid Group S-8 dated 26 July 2001, file no. 333-65968)

10.29*		National Grid Executive Share Option Scheme (Exhibit 4D to National Grid Group S-8 dated 26 July 2001, file no. 333-65968)

31.1		Certification of Principal Executive Officer (filed herewith)

31.2		Certification of Principal Financial Officer (filed herewith)

32		Certifications Pursuant to 18 U.S.C. 1350 (filed herewith)

Registrant

Shares Outstanding at July 12, 2005

New England Power Company

Common Stock, $20.00 par value (all held by National Grid USA)

NEW ENGLAND POWER CO 10-K