Table SECURITIES ANDof EXCHANGE COMMISSIONContents

(f)Table Timing and adequacy of rate relief;Contents

Table THEof COMPANYContents

TheTable resignations of Joseph Callan and Philip R. Sharp as directors were accepted; andContents

TheTable New England Power Pool (NEPOOL) and ISO New England have a separate SMD initiative that is proceeding in parallel to the FERC initiative. The New England SMD was implemented on March 1, 2003. Standards of Conduct: In September 2001, the FERC initiated a NOPR regarding affiliate standards of conduct in both the electric and gas industries. In its proposed rules, the FERC proposed a broad definition of "energy affiliate," which would include the Company’s affiliate National Grid USA Service Company, Inc., as well as the Company’s electric distribution company affiliates. If the FERC were to adopt these rules as proposed, the Company would have to change the way it interacts with its so-called energy affiliates in a manner that could increase costs. Incentive Pricing: In January 2003, the FERC proposed a pricing policy statement indicating that it may provide incentives to transmission owners to join a RTO, an independent transmission company and to invest in new facilities. The FERC has solicited comments on this statement, and the Company cannot predict what the final policy statement will say or whether it will have a material impact on the Company’s financial position or results of operations.Contents

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

ReportTable of Independent AuditorsContents

NewTable England Power CompanyStatements of Retained EarningsContents

TheTable accompanying notes are an integral part of these financial statements.Contents

(a)Table Noncallable.The annual dividend requirement for cumulative preferred stock was approximately $82,000 and $86,000 for 2003 and 2002, respectively.There are no mandatory redemption provisions on the Company’s cumulative preferred stock.NOTE J – LONG-TERM DEBT A summary of long-term debt is as follows:Contents

EachTable member of the board of directors is elected at the annual meeting of stockholders and holds office until the next annual meeting or a special meeting in lieu thereof, and until his or successor is elected and qualified. There are no family relationships between any of the directors and the executive officers listed in the table.Mr. Flynn served as President from January 1999 to April 2003 and was a member of the Company’s Board of Directors during that period. He has been a Vice President of National Grid USA since 2000 and served as Vice President and Director of Rates for National Grid USA Service Company from 1996 to 1999.Mr. Lewis was elected President effective April 16, 2003; he was Vice President from February 26, 2003 until April 16. He has been a Vice President of National Grid USA since November 2002. He was elected President of National Grid Transmission Services Corporation in December 2002 and elected Vice President of Niagara Mohawk Power Corporation and National Grid USA Service Company, Inc. in November 2002. From 2001 to 2002, he was Manager of UK Electricity Services for National Grid. From 1997 to 2001, he was a Network Manager for Services for National Grid.Mr. Cochrane was elected Chief Financial Officer effective August 1, 2002 and Vice President effective January 2002 and has served on the Company’s Board since 2002. He was the Company’s Treasurer from 1998 to January 31, 2002. He has served as National Grid USA’s Chief Financial Officer since January 2001 and Senior Vice President since May 2002 and was Treasurer of National Grid USA (and its predecessor, New England Electric System) and of National Grid USA Service Company from 1998 to 2002. Mr. Cochrane was also Treasurer of Massachusetts Electric Company from 1998 to 2000 and of The Narragansett Electric Company from 1993 to 2000. Mr. Mahoney joined the Company as Vice President in May 2000 at the merger of Montaup Electric Company with the Company. Prior to that he was Vice President, Field Operations, of Eastern Utilities Associates from 1997 to 2000.Mr. Reilly joined the Company’s Board of Directors in 2001 and has been a Vice President of the Company and Secretary and General Counsel of National Grid USA since January 2001. Since 2000 he has been National Grid USA Senior Vice President, and he served as President of Massachusetts Electric Company, The Narragansett Electric Company, Nantucket Electric Company and Granite State Electric Company from 1996 to 2000.Mr. Robinson has been the Company’s Treasurer since January 31, 2002 and has served as Vice President since 1998. He was the Company’s Director of Nuclear Investments from 1997 to 1998.Ms. Rosenqvist was elected Vice President in 1998. Prior to that, she served as Manager of Transmission Tariffs and Contracts for NEP and National Grid USA Service Company.Mr. Schrayshuen has been Vice President since January 31, 2002. He was Director of Electric Assets from 1999 to 2002 and Director of Energy Transactions from 1998 to 1999.Mr. Capomacchio has served as Controller of the Company and of Massachusetts Electric Company, The Narragansett Electric Company, Nantucket Electric Company and Granite State Electric Company since May 2001. Since January 2002, he has served as Vice President and Controller of National Grid USA Service Company and as Controller of Niagara Mohawk Power Corporation. Mr. Capomacchio was Assistant Controller of National Grid USA Service Company from 1998 to 2002. Mr. Jesanis was elected director in 2000. He has served as National Grid USA’s Executive Vice President and Chief Operating Officer since January 31, 2001. He served as Senior Vice President and Chief Financial Officer of National Grid USA’s predecessor, New England Electric System, from 1998 to 2000 and was its Treasurer from 1992 to 1998. Mr. Jesanis is also a director of National Grid USA and of Niagara Mohawk Power Corporation.Mr. Winser was elected director April 16, 2003. He joined the board of National Grid Transco in April 2003 as executive director responsible for UK and US transmission operations. He was appointed Senior Vice President of National Grid USA in January 2002 and was appointed to National Grid USA’s Board of Directors in April 2003. He joined The National Grid Company in 1993, becoming Director of Engineering in 2001.Contents

(a)Table Expressed in terms of ordinary shares of National Grid Transco listed on the London Stock Exchange. (b) This percentage is in relation to option grants made to all employees of National Grid USA and its subsidiaries. (c) The exercise price of $7.117 was converted from 4.815 GBP using a conversion of 1 GBP to $1.478065.Contents

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

ITEMTable 13. CERTAINof RELATIONSHIPS AND RELATED TRANSACTIONSContents

SignatureTable Titleof /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 (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/ Nick Winser Nick Winser DirectorContents

~~Washington,~~UNITED ~~D.C.~~STATES SECURITIES ~~20549~~AND EXCHANGE COMMISSION

~~FORM~~Washington, ~~10-K~~D.C. 20549

~~X ANNUAL~~FORM ~~REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE~~10-K ~~SECURITIES EXCHANGE ACT OF 1934~~

~~For~~þ ~~the~~ANNUAL ~~fiscal~~REPORT ~~year~~PURSUANT ~~ended~~TO ~~March~~SECTION ~~31, 2003~~13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

ORFor the fiscal year ended March 31, 2005

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

CommissionFile Number	Registrant, State of Incorporation,Address and Telephone Number	I.R.S. EmployerIdentification Number
1-6564	New England Power Company	04-1663070
	(a Massachusetts corporation)25 Research Drive Westborough, MA 01582508-389-2000


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

~~Securities~~For ~~registered pursuant to Section 12(b) or Section 12(g) of~~ the ~~Act:~~transition ~~None~~period from to

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 [ X ] NO [ ]


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

~~Indicate~~Securities byregistered ~~check mark if disclosure of delinquent filers~~ pursuant to ~~Item~~Section 12(b) ~~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~~Section 12(g) ~~statements incorporated by reference in Part III~~ of ~~this Form 10-K or any amendment to this Form 10-K [ X ]Indicate by check mark whether~~ the ~~registrant~~ ~~is an accelerated filer (as defined in Exchange~~ Act: ~~Rule 12b-2).~~None ~~YES [ X ] NO [ ]State the~~ ~~aggregate market value of the common equity held by nonaffiliates of the~~ ~~registrant N/A~~

Indicate by check mark whether the ~~number~~registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of ~~shares~~the ~~outstanding~~Securities Exchange Act of 1934 during the preceding 12 months (or for ~~each~~such ofshorter period that the registrant’s ~~classes~~was ofrequired ~~common~~to ~~stock~~file such reports), asand of(2) has been subject to such filing requirements for the ~~latest practicable~~past ~~date~~90 days. YES þ NO o

Registrant	Title	Shares Outstanding at June 24, 2003
New England Power Company	Common Stock, $20.00 par value	3,619,896
	(all held by National Grid USA)

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

TABLE OF CONTENTS
PART I
Item 1.	Business
Item 2.	Properties
Item 3.	Legal Proceedings
Item 4.	Submission of Matters to a Vote of Security Holders
PART II
Item 5.	Market for the Registrants’ Common Equity and Related Stockholders Matters
Item 6.	Selected Consolidated Financial Data
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk
Item 8.	Financial Statements and Supplementary Data
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
PART III
Item 10.	Directors and Executive Officers of the Registrant
Item 11.	Executive Compensation
Item 12.	Security Ownership of Certain Beneficial Owners and Management
Item 13.	Certain Relationships and Related Transactions
PART IV
Item 14.	Controls and Procedures
Item 15.	Exhibits and Reports on Form 8-K
	Signatures
	Certifications

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

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

~~(a)~~Indicate ~~The~~the ~~impact~~number of ~~industry~~shares ~~restructuring,~~outstanding asof ~~more~~each ~~fully~~of ~~set~~the ~~out~~registrant’s ~~under~~classes of common stock, as ~~Regulatory~~of ~~Environment below;~~the latest practicable date.

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

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

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


		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

~~(e) Changes in accounting rules and interpretations which may have an~~2 ~~adverse impact on NEP’s statements of financial position and reported earnings;~~

~~(g)~~Explanatory ~~Adverse~~Note: ~~changes~~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 ~~electric~~fiscal ~~load;~~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.

~~(h)~~This ~~Climatic~~Form ~~changes~~10-K orcontains ~~unexpected~~restated ~~changes~~statements inof ~~weather~~income, ~~patterns;~~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.

~~(i)~~Forward-Looking ~~Failure~~information: toThis ~~recover~~report ~~operation~~contains ~~and~~forward-looking ~~decommissioning~~statements ~~costs~~within ~~associated with~~the ~~nuclear~~meaning ~~generating~~of ~~facilities~~Section 21E of the Securities Exchange Act of 1934, as ~~set~~amended. ~~out~~Throughout ~~under~~this report, ~~Note~~forward-looking Dstatements incan ~~Item~~be 8identified by the words or phrases “will likely result”, “are expected to”, “will continue”, “is anticipated”, “estimated”, “projected”, “believe”, “hopes”, or similar expressions. ~~Financial~~Although the Company believes that, in making any ~~Statements~~such statements, its expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and ~~Supplementary~~results ~~Data~~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:

~~PART~~(a) Ithe 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.

~~ITEM 1.~~3 ~~BUSINESS~~

Name of Company	State of Organization	Type of Business	% Voting Securities Owned by NEP
Connecticut Yankee Atomic Power Company	CT	Ownership of Permanently Shutdown Nuclear Unit (a)	19.5%
Maine Yankee Atomic Power Company	ME	Ownership of Permanently Shutdown Nuclear Unit (a)	24.0%
Vermont Yankee Nuclear Power Corporation	VT	Rights to proceeds from sale of a Nuclear Unit (a)	23.9%
Yankee Atomic Electric Company	MA	Ownership of Permanently Shutdown Nuclear Unit (a)	34.5%
New England Hydro Transmission	NH	Electric Transmission	3.4%
New England Hydro-Transmission Electric Co., Inc.	MA	Electric Transmission	3.4%

PART I

~~(a)~~ITEM For information on the Company’s ownership interests in nuclear generating units, see Item. 8 Financial Statements and Supplementary Data. The facilities of NEP, together with the four New England electricity delivery companies, constitute an electrical transmission and distribution system that is directly interconnected with other utilities in New England and New York State, and indirectly interconnected with utilities in CanadaAcquisition of EUA: The acquisition of Eastern Utilities Associates (EUA) by National Grid USA was completed on April 19, 2000. On May 1~~, 2000, Montaup Electric Company (Montaup), formerly a subsidiary of EUA, was merged into the Company~~. BUSINESS

New ~~EMPLOYEE~~England ~~RELATIONS~~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.

AtNEP’s business is primarily the transmission of electricity in wholesale quantities to other ~~March~~electric 31utilities, ~~2003~~principally its New England electricity distribution affiliates: Massachusetts Electric Company, ~~NEP~~The ~~had~~Narragansett 7Electric ~~employees~~Company, 6Granite State Electric Company and Nantucket Electric Company. The facilities of ~~whom~~NEP, ~~are~~together ~~members~~with those of these affiliates, constitute an electricity transmission and distribution system that is directly interconnected with the facilities ~~labor~~of its New York affiliate, Niagara Mohawk Power Corporation and other utilities in New ~~organization~~England and New York State, ~~the~~and ~~International~~indirectly ~~Brotherhood~~interconnected with those of ~~Electrical~~utilities ~~Workers~~in Canada.

~~TRANSMISSION~~Capital ~~AND~~stock: ~~NUCLEAR~~Holders ~~GENERATION~~of NEP’s common stock and 6% Cumulative Preferred Stock have general voting ~~BUSINESS~~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.

~~Description of Business~~Investees: The Company’s ~~primary~~holds business is the transmission of electric energy to other electric utilities, principally its four New England distribution affiliates. NEP owns a system of transmission lines and substations. The Company continues to own minority ~~equity~~interests ~~interest~~ in ~~four~~ ~~nuclear~~three ~~power~~ companies, ~~none~~(the ofYankees) ~~which~~that ~~owns~~own ~~any operating~~ nuclear ~~units.~~ ~~The Company sold its 10 percent interest in a jointly held nuclear~~ generating ~~plant~~ infacilities ~~November~~that ~~2002.~~are ~~Additionally,~~permanently ~~the~~retired Company owns a nine percent interest in the Wyman 4 fossil fuel plant located in Yarmouth, Maine. Purchased Power Transfer Agreement: As part of the sale of the Company’s nonnuclear generating business to USGen New England, Inc. (USGen) , a wholly owned subsidiary of PG&E, in 1997, NEP signed a purchased power transfer agreement through which USGen purchased the Company’s entitlement to approximately 1,100 MW of power procured under long-term contracts. In the ensuing period, contract terminations, assignments and ~~expirations~~ ~~have~~are ~~reduced~~conducting ~~this~~decommissioning ~~entitlement to approximately 580 MW~~operations. ~~For more~~ ~~information, see Item 8. Financial Statements and Supplementary Data.Segments:~~ The Company's ~~reportable~~also ~~segments~~owns ~~are~~minority ~~electric transmission~~interests ~~and electric distribution. The Company is engaged principally~~ in ~~the~~ ~~business~~two ofcompanies ~~electric~~that ~~power~~transmit ~~transmission.~~hydro For more information, see Item 8. Financial Statements and Supplementary Data.Financial Information about Geographic Regions: NEP’s business is primarily the transmission of electric energy in wholesale quantities to other electric utilities, principally its distribution affiliates, National Grid USA’s four New England electricity ~~delivery companies which are located in~~from ~~Massachusetts, New Hampshire and Rhode Island: Massachusetts Electric Company, Nantucket Electric Company, the Narragansett Electric Company and Granite State Electric Company~~Canada. All of the Company customers and assets are concentrated in the northeast region of the United States. For more information, see Item 8. Financial Statements and Supplementary Data.Regulation: Numerous activities of the Company are subject to regulation by various federal agencies. Under the 1935 Act, many transactions of the Company are subject to the jurisdiction of the SEC. Under the Federal Power Act, the Company is subject to the jurisdiction of the FERC with respect to rates and accounting. In addition, the NRC has broad jurisdiction over nuclear units and federal environmental agencies have broad jurisdiction over environmental matters. For more information, see Item 8. Financial Statements and Supplementary Data.Environmental Requirements: The Company isowns ~~subject~~voting ~~to federal,~~stock ~~state, and local environmental regulation~~ of, among other things, wetlands and flood plains; air and water quality; storage, transportation, and disposal of hazardous wastes and substances; underground storage tanks; and land-use. For more information, see Item 8.Financial Statements and Supplementary Data.ISO 14001: In June 2001, the ~~Company~~following ~~announced that~~companies ~~its transmission business achieved ISO (International Organization of Standardization) 14001 registration of its Environmental Management System, the first linear electric utility system~~ in the ~~country~~amounts ~~to achieve such designation.~~indicated: ~~This also marked the first ISO 14001 registration of a high-voltage direct~~ current (HVDC) transmission system in the U.S. The registration certifies that all activities, products, and services required to operate, maintain, and construct transmission lines, rights-of-way, HVDC converter terminals, and vegetation management activities meet the requirements of the internationally accepted ISO 14001 environmental standard.ITEM 2. PROPERTIES

TRANSMISSION PROPERTIES


			% 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	%

The Company’s integrated system consists of approximately 2,800 circuit miles of transmission lines, and approximately 120 substations. The properties of the Company also include the ownership interests of New England Electric Transmission Corporation (NEET), New England Hydro-Transmission Electric Company, Inc. (Mass. Hydro), and New England Hydro-Transmission Corporation (N.H.Hydro) in the Hydro-Quebec Interconnection, and an integrated system of transmission lines, substations, and distribution facilities. The Company is a ~~participant in the New England Power Pool (NEPOOL~~)~~. The~~ ~~NEPOOL~~For ~~Agreement~~detail provides for coordination of the operation of the generation and transmission facilities of its members. The NEPOOL Agreement further provides for New England-wide central dispatch of generation by the Independent System Operator (ISO). ISO New England was activated on ~~July~~ ~~1, 1997 and has been operating~~ the ~~control area since that time. It operates under contract with NEPOOL and is governed by an independent board of directors. NEPOOL~~Company’s ~~Open~~ownership ~~Access~~interests Transmission Tariff, which covers service across pool transmission facilities, is administered by ISO New England. In May 1999, NEPOOL and ISO New England began implementing the NEPOOL competitive market system. The market system establishes markets for several tradable energy and reserve products. Implementation of the markets also has resulted in the ~~imposition of certain costs including congestion related costs. By Order issued June 28~~Yankees, ~~2000,~~see ~~FERC~~Note ~~conditionally~~C approved a congestion management system and multi-settlement system (CMS/MSS). The CMS/MSS includes a Financial Transmission Rights scheme, a transmission planning process, and locational marginal pricing. The Standard Market Design (SMD) which was implemented on March 1, 2003 is based on the market system presently in place in the PJM (Pennsylvania, New Jersey, Maryland) interconnection and in New York, and is intended to bring greater consistency to power markets in the Northeast. NEPOOL’s governance structure consists of five sectors: transmission owners, generators, suppliers, public power, and end users. National Grid USA participates in the transmission owners sector. The transmission sector accounts for 20 percent of the NEPOOL vote and the National Grid USA Companies account for one-seventh of the transmission sector vote. Under NEPOOL’s revised governance structure, all National Grid USA companies are considered “~~related~~Nuclear ~~persons~~Investments” and therefore receive only a single vote.Interconnection with Quebec: NEET owns and operates a portion of an international transmission interconnection between the electric systems of Hydro-Quebec and New England. Mass. Hydro and N.H. Hydro own and operate facilities in ~~connection~~Item with an expanded second phase of this interconnection. New England Hydro Finance Company, Inc. (N.E. Hydro Finance) provides the debt financing to Mass. Hydro and N.H. Hydro for the capital costs of the interconnection. National Grid USA owns 100% of the voting stock of NEET and 57.47% of the voting stock of both Mass. Hydro and N.H. Hydro. Mass. Hydro and N.H. Hydro each own 50% of the voting securities of N.E. Hydro Finance. NEET, Mass. Hydro, and N.H. Hydro own and operate a 450 kV direct current transmission line and related terminals to interconnect the New England and Quebec transmission systems (the Interconnection). The transfer capability of the Interconnection is currently rated at 2,000 megawatts (MW). Operating limits implemented by adjacent Power Pools covering New York, New Jersey, Pennsylvania, and Maryland often restrict the effective transfer capability to levels of 1,200 MW to 1,400 MW.The Interconnection has two phases. The Company’s participation in both is approximately 22 percent. The Company and the other participants have entered into support agreements that end in 2020. Under the support agreements, NEP has agreed to guarantee its share of debt financing for the second phase. At March 31, 2003, the Company guaranteed approximately $18 million of project debt, including $3 million originally guaranteed by Montaup, with terms through 2015. NEP’s rights and obligations under its support agreements were transferred to the purchaser of its nonnuclear generation, but NEP retained Montaup’s rights and obligations under its support agreement. NEP remains an obligor under the support agreements, for the portion of the rights it transferred until 2020. Costs associated with these support agreements are recoverable through the Company’s transmission rates. ITEM 3. LEGAL PROCEEDINGSMillstone 3 Prudence Challenge: In November 1999, NEP entered into an agreement with Northeast Utilities (NU) to settle certain claims. Among other things, the settlement agreement required NU to include NEP’s 16.2 percent ownership interest in Millstone Unit 3 in an auction of NU’s share of the unit. Upon the closing of the sale, NEP was to receive a fixed amount, regardless of the actual sale price. In March 2001, the Millstone units were sold, including NEP’s interest, for $1.3 billion. In accordance with the settlement agreement, NEP was paid approximately $27.9 million, from which NEP paid approximately $5.8 ~~million to the decommissioning trust fund~~.~~Regulatory~~ ~~authorities~~Financial ~~from~~Statements ~~Rhode Island, New Hampshire~~ and ~~Massachusetts~~ ~~have~~Supplementary expressed intent to challenge the reasonableness of the settlement agreement, on the ground that NEP would have received approximately $140 million of sale proceeds if there had been no agreement with NUData. In the event that one or more of the states proceed with such a challenge, the dispute will be resolved by the FERC. NEP believes it has a strong argument that it acted prudently, as the amount it received under the settlement agreement was the highest sale price for a nuclear unit at the time the agreement was reached.Town of Norwood Litigation: NEP continues to be engaged in litigation in judicial and administrative forums with the Town of Norwood (Norwood), Massachusetts, which was an all-requirements customer of NEP from 1983 to 1998. The contract term ran to 2008, and Norwood announced its intention to terminate the contract prematurely in response to NEP’s planned sale of its generating facilities to USGen New England, Inc. (USGen). NEP responded to Norwood’s proposed termination by filing a Contract Termination Charge (CTC) at the FERC. The litigation is as follows:State Collection Action: NEP filed a collection action in Massachusetts Superior Court (Worcester County) to collect the CTC charge, which Norwood has refused to pay. Through March 31, 2003, NEP’s billings are approximately $59 million, including late payment charges, which run at 1.5% per month on the unpaid balance. In March 2001, the Superior Court ruled that Norwood has breached the agreement by not paying the CTC charge, and ordered Norwood to make regular and substantial payments to an escrow account (which today contains about $23 million). Norwood appealed the judgment, oral argument took place in March 2003 and the parties are awaiting a decision. FERC 206 Proceeding: In December 2002, Norwood filed a challenge to the CTC rate with the FERC under Section 206 of the Federal Power Act. Under this Section, the FERC has the power to grant prospective relief only (unless the rate was computationally flawed from the outset). Norwood has the burden of proof. NEP has moved to dismiss the proceeding and alternatively, to delay proceedings until Norwood pays NEP its full CTC. In a draft order released on or about June 25, 2003, FERC granted NEP's motion to dismiss those portions of Norwood's complaint under Section 206 of the Federal Power Act that Norwood previously litigated before FERC and the federal district court, and set down for hearing Norwood's challenge to the factors that are used to calculate the CTC rate. In so doing, the FERC set a refund date of February 21, 2003 and referred the matter initially to a FERC settlement judge, consistent with its normal procedures. The draft order is subject to further modification by FERC before it is issued in final form. Federal Court Antitrust Claim: In 1997, Norwood filed a lawsuit in federal district court in Boston challenging NEP’s proposed divestiture of its generating facilities. Following the district court’s dismissal of all of its claims, the First Circuit Court of Appeals reinstated Norwood’s claim that the sale to USGen violated Section 7 of the Clayton Act on the ground that USGen had acquired market power. The First Circuit characterized the claim as weak in light of the fact that FERC had found no anticompetitive consequences from the sale, and invited the district court to address whether the FERC’s decision precluded further litigation. This issue was argued to the district court in 2001, but no decision has been rendered, in part because the original judge who heard argument subsequently recused herself.ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERSOn February 20, 2003, a Special Meeting of Shareholders was held. By unanimous vote of the 3,619,896 shares present of 3,632,846 total shares having general voting rights:

~~The Company’s bylaws were amended to delete provisions relating to the~~4 Company’s former ownership of operating nuclear stations, namely by terminating the Special Nuclear Committee and removing Nuclear Regulatory Commission requirements regarding the nationality of the officers and directors;

~~The~~Regulation: ~~number~~Numerous activities of ~~directors~~the ~~was~~Company ~~decreased~~are ~~from~~subject ~~eight~~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). ~~six~~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.

~~PART~~The IICompany 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.

~~ITEM~~New ~~5. MARKET~~England ~~FOR~~RTO ~~THE~~and ~~REGISTRANT'S~~Rate ~~COMMON~~Filing: ~~EQUITY~~FERC ~~AND~~issued ~~RELATED~~two ~~SECURITY HOLDER~~orders ~~MATTERSThe~~in ~~common~~2004 ~~stock of NEP is held solely by National Grid USA,~~ and ~~therefore~~two ~~indirectly~~in by2005 ~~National~~that ~~Grid~~approved ~~Transco plc. There is no~~the ~~public~~establishment ~~trading~~of ~~market for~~ the ~~Company’s~~RTO ~~common stock,~~ and ~~the~~resolved ~~Company~~certain ~~sold no~~issues ~~equity~~concerning ~~securities during~~ the ~~period~~proposed ~~covered~~return ~~by this Annual Report. For information about the Company's payment of dividends and restrictions~~ on ~~those payments,~~equity ~~see Item 6, Selected Financial Data, and Item 8.Financial Statements~~for ~~and~~New ~~Supplementary~~England ~~Data, Note I~~PTOs. ~~ITEM~~Other ~~6. SELECTED~~return ~~FINANCIAL DATAThe~~issues ~~following~~were ~~tables~~ set ~~forth selected financial information~~ for ~~NEP~~hearing. ~~for~~A ~~the~~number ~~years~~of ~~ended March 31~~parties, ~~2003,~~including ~~2002~~NEP, ~~and 2001, respectively, and~~ ~~for the years ended December 31, 1999 and 1998, respectively, and for the three months ended March 31, 2000 and 1999, respectively, which~~ have ~~been~~filed ~~derived~~appeals from ~~the~~ ~~financial~~one ~~statements~~or more of ~~NEP~~those ~~and~~orders ~~should be read in connection therewith. On March 22, 2000, the Company’s former parent New England Electric Systems merged~~ with ~~National Grid Transco plc (formerly National Grid Group plc) in a purchase business combination recorded under~~ the ~~“push-down”~~ ~~method~~US ofCourt ~~accounting, resulting in a new basis~~ of ~~accounting~~ ~~for~~Appeals the “successor” period beginning March 22, 2000. Information relating to all “predecessor” periods prior to the acquisition is presented using the Company’s historical basis of accounting. The following selected financial data for the ~~Company may not be~~District ~~indicative~~ of ~~the~~Columbia ~~Company’s future financial condition, results of operations or cash flows~~Circuit.

			Year Ended March 31,( Successor)			Three Months Ended March 31, (Predecessor)		Year Ended December 31,(Predecessor)
(In millions)			2003	2002	2001	2000	1999	1999	1998
Operating revenue	$ 514			$ 560	$ 656	$ 135	$ 167	$ 596	$1,218
Net Income		$ 77		$ 77	$ 58	$ 14	$ 20	$ 71	$ 123
Income from continuing operations per average common share		**		**	**	**	**	**	**
Total assets		$2,921		$2,740	$2,889	$2,630	$2,282	$2,303	$2,415
Long-term debt		$ 410		$ 410	$ 410	$ 372	$ 372	$ 372	$ 372
Cumulative preferred stock		$ 1		$ 2	$ 1	$ 1	$ 1	$ 2	$ 1
Dividends per common share		**		**	**	$ 4	-	$ 241	$ 131

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.

** AllNEP ofand ~~NEP’s~~the ~~shares~~other ofPTOs ~~common~~participated ~~stock~~in ~~are~~FERC ~~owned~~proceedings byto ~~its~~determine ~~parent~~outstanding ROE issues, ~~company~~including ~~therefore~~base return on equity (ROE) and the proposed 1% ROE incentive for new transmission investment. On May 27, ~~per~~2005, ~~share~~the ~~data~~administrative islaw judge issued an initial decision which concluded that the base ROE should be 10.72% and that NEP and other PTOs are not ~~relevant~~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.

~~ITEM~~Compliance ~~7. MANAGEMENT'S~~with ~~DISCUSSION~~Environmental ~~AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.FERC Proceedings~~Requirements: The ~~FERC is contemplating major changes to the regulatory structure that governs the~~ Company’s ~~business.~~operations ~~Several~~and ~~proposals~~facilities are ~~under~~subject ~~consideration, any of~~to ~~which~~numerous ~~may affect how the Company does business. The Company cannot predict which or how many of the proposals the FERC will adopt or in what form~~federal, orstate ~~whether they~~and ~~will~~local ~~have~~laws aand ~~material~~regulations ~~impact~~relating onto the ~~Company’s~~environment ~~financial position or results of operations.Regional Transmission Organizations: Transmission owners,~~ including ~~the Company~~, ~~have been working to develop an~~among ~~alternative~~other ~~Regional~~things, ~~Transmission~~requirements ~~Organization~~concerning ~~(RTO)~~air ~~structure.~~and Itwater isquality; ~~not~~wetlands ~~clear what~~and ~~structure~~flood ~~will~~plains; ~~emerge from these negotiations. In August 2002~~storage, ~~the New~~ ~~York~~transportation and ~~New~~disposal ~~England~~of ~~ISOs~~hazardous ~~filed~~wastes aand ~~proposal~~substances; ~~with~~storage ~~the~~tanks; ~~FERC~~and ~~to form an RTO but~~site ~~withdrew it in November 2002 after several parties, including National Grid USA, filed protests~~remediation. ~~Currently,~~ ~~the~~The Company isbelieves ~~working~~it ~~with~~is ~~stakeholders~~handling inidentified ~~New England~~wastes toand ~~develop~~by-products ain ~~proposal for~~ a ~~New England–only RTO or an ISO that~~manner ~~complies~~consistent with ~~FERC’s~~applicable ~~standard market design principals~~requirements. ~~Such~~ aThe ~~proposal is~~environmental ~~expected~~management tosystems befor ~~filed in October 2003. Standard Market Design: In July 2002,~~ the ~~FERC issued a formal notice of proposed~~Company’s ~~rulemaking~~distribution ~~(NOPR) on standard market design (SMD). The proposed rules address transmission pricing~~ and ~~planning, the role of merchant~~ transmission, ~~and~~facilities ~~other issues~~are ~~that~~certified would directly affect the Company. The FERC issued a White Paper on April 28, 2003 outlining a proposed wholesale power market platform that it would require in any final rules in this proceeding. The White Paper embodies FERC's response to the ~~comments~~International ~~that~~Organization ~~it received in this proceeding. FERC~~for ~~states~~Standardization ~~that it intends to issue a rule requiring that every public utility join an independent entity~~ (~~either an RTO or an~~ ISO) 14001 ~~that would be responsible for transmission service, tariff design, system operations and markets within a region~~standard. ~~States~~ ~~would~~Management ~~have~~believes ait ~~significant~~is ~~role~~probable inthat ~~regional~~costs ~~transmission planning,~~associated ~~tariff~~with ~~design~~environmental ~~and~~compliance inwill ~~ensuring~~continue ~~resource adequacy. Transmission owners that are market participants would have limited authority~~ to ~~manage~~be ~~transmission. Independent~~recovered ~~transmission~~through ~~companies~~the ~~may~~ratemaking ~~manage a broader set of functions~~process. InThe ~~addition, to the extent the~~ Company’s ~~wishes~~compliance tohas ~~pursue~~no ~~opportunities~~material ~~related~~effect ~~to transmission~~on ~~projects, the FERC rulings in the SMD proceeding and other~~its ~~proceedings may limit the Company's ability to do so.~~

~~On July 12, 2002, the U.S. Court of Appeals issued an order concerning~~5 Pennsylvania-New Jersey-Maryland ISO’s relationship with its transmission owners. This order was favorable precedent to the Company because it suggested that transmission owners that join ISOs still maintain significant authority to propose transmission rates and to withdraw from such ISOs. On December 19, 2002 and May 14, 2003, however, the FERC issued decisions that appear to narrow this authority. On May 20, 2003 the U.S. Court of Appeals issued a ruling declaring that the FERC’s December 19, 2002 order had violated the Court’s mandate. It is not clear whether the FERC’s decision will stand, but the uncertainty surrounding this issue will likely affect the Company’s relationship with ISO New England and with any future RTO. Currently the Company, other transmission owners and ISO New England is seeking to work out mutually agreeable arrangements that would govern the relationship between transmission owners and the RTO/ISO as part of the anticipated RTO/ISO filing to be made in October 2003.

~~CRITICAL~~capital ~~ACCOUNTING~~expenditures, ~~POLICIES~~earnings or competitive position.

~~Certain~~The ~~critical~~Company ~~accounting~~has ~~policies~~implemented ~~are~~an ~~based~~environmental onaudit ~~assumptions~~program ~~and conditions~~to ~~that~~identify ifany ~~changed~~potential ~~could~~areas ~~have a material effect on the financial condition, results~~ of ~~operations and liquidity of the Company. The following~~ ~~accounting~~concern ~~policies are particularly important to the financial condition~~ and ~~results~~ ofaid ~~operations~~in ofcompliance ~~the~~with ~~Company:~~legal ~~regulatory accounting, goodwill accounting and pensions~~requirements.~~Regulatory~~ ~~Accounting: Electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general.~~ The Company ~~applies~~is ~~the~~also ~~provisions~~currently ofconducting ~~SFAS No.~~a ~~71,~~program ~~“Accounting~~to ~~for~~investigate ~~the~~and ~~Effects of Certain Types of Regulation” (FAS 71)~~remediate, ~~which~~as ~~requires~~necessary ~~regulated entities, in appropriate circumstances,~~ to ~~establish~~ ~~regulatory~~meet ~~assets~~current orenvironmental ~~liabilities~~standards, ~~and thereby defer the income statement impact of~~ certain ~~charges or revenues because they are expected to be~~ ~~collected~~properties orwhich ~~refunded through future customer billings. In 1997,~~ the ~~Emerging Issues~~Company ~~Task~~has ~~Force~~learned ofmay ~~the FASB concluded that a utility that had received approval to recover stranded costs through regulated rates would~~ be ~~permitted~~contaminated ~~to continue to apply FAS 71 to the recovery of stranded costs.The Company has received authorization from the FERC to recover through CTCs substantially all of the costs associated~~ with ~~its~~industrial ~~former~~waste, ~~generating~~as ~~business~~well ~~not recovered~~as ~~through~~investigating ~~the~~identified ~~divestiture.~~industrial ~~Additionally,~~waste ~~FERC~~sites ~~Order~~as ~~No. 888 enables transmission companies~~ to ~~recover~~which ~~their~~it ~~specific~~may ~~costs~~be ofdetermined ~~providing~~that ~~transmission service. Therefore, substantially all of~~ the Company~~’s business, including the~~ ~~recovery~~has ~~of its stranded costs, remains under cost-based rate regulation~~contributed. As aThe ~~result of applying FAS 71, the~~ Company has ~~recorded~~also abeen ~~regulatory asset~~advised ~~for the costs~~ that ~~are~~various ~~recoverable from customers through the CTC. At March 31~~federal, ~~2003~~state ~~and~~or ~~2002,~~local ~~net regulatory assets amounted to approximately $1.3~~agencies ~~billion~~believe ~~and~~certain ~~$1.4~~properties ~~billion,~~require ~~respectively,~~investigation ~~including $0.8 billion~~ and ~~$1.0~~has ~~billion, respectively,~~prioritized ~~related to~~ the ~~above-market~~sites ~~costs~~based ofon ~~purchased power contracts,~~available ~~$0.3~~information ~~billion~~in ~~and~~order ~~$0.2 billion, respectively, related~~ to ~~accrued~~enhance ~~Yankee nuclear plant costs, and $0.2 billion and $0.2 billion, respectively, related to other net CTC regulatory assets. Goodwill: The company applies~~ the ~~provisions~~ ofmanagement ~~Statement~~ of ~~Financial~~investigation ~~Accounting Standards (SFAS) No. 142, “Goodwill~~ and ~~Other Intangible Assets” (FAS 142). In accordance with FAS 142~~remediation, ~~goodwill~~if ~~must be reviewed for impairment at least annually~~necessary. ~~The Company~~ ~~utilized a discounted cash flow approach incorporating its most recent business~~ ~~plan forecasts in the performance of the annual goodwill impairment test. The~~ result of the annual analysis determined that no adjustment to the goodwill carrying value was required.Pensions: The Company has recognized an additional minimum pension liability of $94 million on its balance sheet reflecting this under funded pension obligation. However, due to the nature of its rate plan the Company has not charged other comprehensive income but has instead recorded a regulatory asset.

~~RESULTS~~Purchased OFPower ~~OPERATIONS~~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.

~~EARNINGS~~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.

~~Net~~Employee ~~income~~Relations: ~~for~~The ~~the~~Company ~~twelve~~receives ~~months~~substantial ~~ended~~support ~~March~~for ~~31,~~its ~~2002~~activities ~~increased~~from the employees ~~approximately~~of ~~$18~~National ~~million~~Grid ~~compared~~USA ~~with~~Service ~~the~~Company, ~~same~~Inc. ~~period~~(Service inCompany), ~~2001.~~an ~~The~~affiliated ~~increase~~company isthat provides ~~primarily~~administrative ~~due~~support to ~~the~~all ~~adoption~~National ofGrid ~~Statement~~USA ofcompanies ~~Financial~~in ~~Accounting~~accordance ~~Standards~~with Nothe 1935 Act. The ~~142~~Company ~~“Accounting~~also ~~for~~receives ~~Goodwill~~construction ~~and~~services ~~Other~~from ~~Intangible~~Service ~~Assets”~~Company. ~~(FAS~~The ~~142),~~Company reimburses Service ~~effective~~Company ~~April~~for 1,the ~~2001,~~costs ~~which~~associated ~~required~~with ~~the~~those ~~cessation~~services. ofFor ~~goodwill~~a ~~amortization~~more detailed discussion of Service (Company support for the Company, see Note A- “Accounting Policies” in Item 8). ~~Also~~Financial ~~contributing~~Statements and toSupplementary ~~the~~Data. ~~increase~~In inaddition, ~~earnings~~at isMarch 31, a2005, ~~decrease~~the ~~in interest~~Company ~~expense~~had ~~due~~seven toemployees, ~~decreased~~six ~~interest~~of whom ~~rates~~are onmembers ~~variable-rate~~of ~~long-term~~a ~~debt and~~labor organization, the ~~refinancing~~International Brotherhood of ~~short-term~~Electrical ~~debt~~Workers.~~REVENUES~~

~~Operating~~ITEM revenue: In the fiscal year ended March 31, 2003, the Company was no longer receiving revenue related to its obligation to provide electric supply to serve certain customers of The Narragansett Electric Company, an affiliate. Effective December 1, 2001, the Company was no longer obligated to provide this power to Narragansett's customers, which is the primary reason for the decrease in revenues for the year ended March 31, 2003 of approximately $46 million. In addition, revenue decreased as a result of reduced sales of power purchased from the Vermont Yankee Nuclear Generating Station (Vermont Yankee) which was sold in July 2002. The decrease in revenues was partially offset by an increase in nuclear revenues, due to the recovery of a portion of increased nuclear operating expenses and increased transmission revenue compared with the same period in 2002.Operating revenue for the twelve months ended March 31, 2002, decreased approximately $96 million compared with the same period in 2001. The decrease is primarily attributable to reduced kilowatt-hour (kWh) sales due to the sale of the Millstone 3 nuclear generating unit and the effect of a refueling outage at the Vermont Yankee nuclear power plant during the year. The decrease is also related to reduced CTC revenue due to fully reconciling true-up mechanisms that allow the Company to adjust revenues proportionately with correlating expenses. Partially offsetting these decreases were increased transmission revenues. OPERATING EXPENSESOperating expenses for the twelve months ended March 31, 2003 and 2002 decreased approximately $41 and $94 million, respectively, compared with the same periods in the preceding fiscal years. The following paragraphs describe the respective decreases.Fuel for generation expense for the twelve months ended March 31, 2003 increased approximately $3 million, compared with the same period in 2002 due to increased fuel expense at the Wyman 4 plant. Fuel for generation expense for the twelve months ended March 31, 2002 decreased approximately $6 million, primarily due to the sale of Millstone 3 and decreased fuel expense at the Wyman 4 plant.Purchased power expense for the fiscal year ended March 31, 2003, decreased approximately $51 million compared with the same period in 2002. The decrease was primarily caused by the termination of the company’s obligation to provide power to Narragansett Electric Company as described in Operating Revenue, above. In addition, purchased power expense decreased in connection with the sale of the Vermont Yankee nuclear station in July 2002. Also contributing to the decrease was reduced ongoing payments resulting from the November 2002 buyout of a purchased power contract. Purchased power expense for the fiscal year ended March 31, 2002 decreased approximately $17 million compared with the same period in 2001. The decrease was caused primarily by the termination of the Company’s obligation to provide power to Narragansett Electric Company as described in Operating Revenue, above. The decrease is partially offset by increased costs attributed to a refueling outage at Vermont Yankee during the quarter ended June 30, 2001, the refund of excess nuclear insurance and tax credits to Maine Yankee and Connecticut Yankee during the quarter ended December 31, 2000 and the inclusion of Montaup’s purchased power costs throughout the fiscal year ended March, 2002 in comparison to eleven months in fiscal year 2001.Operation and maintenance expense decreased approximately $1 million for the fiscal year ended March 31, 2003, compared with the same period in 2002. The decreased cost is primarily the result of the sale of Seabrook Nuclear Generating Station (Seabrook) in November 2002. The decrease was partially offset by increased costs from a refueling outage at Seabrook prior to the sale and increased transmission maintenance costs. Operation and maintenance expense for the fiscal year ended March 31, 2002 decreased approximately $27 million compared with the same period in 2001 primarily as a result of the sale of Millstone 3. Offsetting the decrease was increased pension costs as compared with the same period in the prior year due primarily to the sale of Millstone 3. Purchased power contract buyout and nuclear fuel amortization expense for the fiscal years ended March 31, 2003 and 2002 increased approximately $2 ~~million and $6 million, respectively, as compared with the same periods in the previous fiscal years~~. The increases were due primarily to scheduled purchased power contract buyout cost increases based upon rate agreements. The increases were partially offset by decreased nuclear fuel amortization due to the sale of the Millstone plant in March 2001 and the Seabrook plant in November 2002.Other depreciation and amortization expense for the fiscal year ended March 31, 2003, increased by approximately $7 million compared with the same period in 2002. The increase is due to the Company’s payment in November 2002 of approximately $5 million to the Seabrook decommissioning trust fund for its share of the balance needed to raise the fund to the level required in the plant sales agreement.Other depreciation and amortization expense for the twelve months ended March 31, 2002 decreased approximately $48 million compared with the same period in 2001. This decrease is due to reduced nuclear depreciation and decommissioning expense as a result of the sale of Millstone 3 in March 2001, and the full recovery of the Company’s CTC-related fixed costs associated with its generating plants and regulatory assets (excluding Montaup’s fixed costs) at the end of 2000.Other Income and Expense for the fiscal year ended March 31, 2003 was comparable with the same period in 2002. Other income for the twelve months ended March 31, 2002 increased approximately $13 million compared with the same period in 2001. The increase is due primarily to the cessation of goodwill amortization as a result of the adoption of FAS 142 and an increase in allowance for equity funds used during construction, partially offset by reduced earnings from the Yankees and decreased interest income from other investing activities.Interest Expense for the fiscal year ended March 31, 2003, decreased approximately $6 million compared with the same periods in 2002, primarily due to decreased interest rates on the Company’s variable rate long-term debt. Interest expense for the fiscal year ended March 31, 2002 decreased approximately $7 million compared with the same period in 2001 primarily due to decreased interest rates on the Company’s variable-rate long-term debt and the refinancing of short-term debt.PROPERTIES

~~LIQUIDITY~~The ~~AND~~Company’s ~~CAPITAL~~integrated ~~RESOURCES~~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.

AtHydro-Quebec ~~March~~Interconnection: ~~31,~~Three ~~2003~~affiliates ~~the Company’s principal sources~~ of liquidity included cash and cash equivalents of approximately $248 million and accounts receivable of $137 million. The Company has a working capital balance of approximately $245 million.Net cash flows provided by operating activities for the ~~fiscal year ended March 31, 2003, was approximately $102 million. The~~ Company ~~made~~were acreated ~~payment~~to ofconstruct ~~approximately~~and ~~$77 million in November~~operate ~~2002~~transmission ~~under~~facilities ato ~~1997~~transmit ~~purchased~~ power ~~transfer~~from ~~agreement~~Hydro-Quebec ~~with~~to ~~USGen,~~New ~~the purchaser of its generation assets~~England. ~~The~~Under ~~payment formally releases~~ the ~~Company as the~~financial ~~obligor~~and ~~from~~organizational ~~one~~agreements of (the ~~power~~Support ~~purchase~~Agreements) ~~agreements~~entered ~~covered~~into byat the ~~transfer agreement~~time ~~and~~these ~~reduces future payments under that agreement.Net cash~~facilities ~~flows~~were ~~provided~~constructed, ~~by investing activities for~~ the ~~fiscal~~Company ~~year~~agreed ~~ended March 31, 2003, increased approximately $61 million compared with same period in 2002, primarily due~~ to guarantee a ~~one-time~~portion ~~cash inflow~~ of the ~~proceeds~~project ~~from the sale of Seabrook in November 2002~~debt. At March 31, 2005, ~~2003~~ the Company had ~~no short-term~~guaranteed ~~debt~~approximately ~~outstanding. The Company has regulatory approval to issue up to~~ $~~375~~ 13 million of ~~short-term~~project debt~~. National Grid USA and certain subsidiaries~~, ~~including~~ ~~the Company,~~ with ~~regulatory~~terms ~~approval, operate a money pool to more~~through ~~effectively utilize cash resources and to reduce outside short-term borrowings~~2015. ~~Short-term~~ ~~borrowing~~As ~~needs~~a ~~are~~result ~~met first by available funds~~ of the ~~money~~termination ~~pool participants.~~of ~~Borrowing~~an ~~companies~~assignment ~~pay interest at a rate designed to approximate the cost~~ of ~~outside~~certain ~~short-term~~obligations ~~borrowings.~~under ~~Companies that invest in~~ the ~~pool~~Support ~~share~~Agreements ~~the interest earned~~ on aApril 1, ~~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~~2004, ~~2003~~ the Company ~~had~~recorded ~~lines of~~a ~~credit~~capital ~~and~~lease ~~standby bond purchase facilities~~ with ~~banks~~an ~~totaling~~offsetting ~~$419~~liability ~~million~~of ~~which is available to provide liquidity support for~~ $~~410~~ 38 million. ofThe ~~the~~ Company’s ~~long-term~~remains ~~bonds~~an inobligor ~~tax-exempt~~under ~~commercial~~the ~~paper~~Support ~~mode,~~Agreements ~~and~~ for ~~other~~ ~~corporate~~its ~~purposes.~~portion ~~The Company's line~~ of ~~credit expires and is renewed~~the ~~each~~project ~~December.~~debt ~~The~~until ~~Company's standby bond purchase facility expires and is renewed each September~~2020. ~~There~~See ~~were~~Note noB ~~borrowings~~“Rate ~~under these lines of credit at March 31, 2003. Fees are paid on the lines~~ and ~~facilities~~Regulatory” in ~~lieu of compensating balances~~Item 8.~~Utility~~ ~~Plant~~Financial ~~Expenditures:~~Statements ~~Cash~~and ~~expenditures~~Supplementary ~~for~~Data ~~the Company~~ for ~~utility~~a ~~plant~~discussion ~~totaled~~of ~~$42 million for~~ the ~~fiscal~~ ~~year~~termination ~~ended March 31, 2003~~ and ~~were~~the ~~primarily~~recovery ~~transmission-related.~~of ~~The funds~~costs ~~necessary~~associated ~~for utility plant expenditures during the period were primarily~~with ~~provided~~these bySupport ~~internal funds~~Agreements.

	Future Estimated Construction Expenditures for the years ended March 31,
(In millions)	2004	2005	2006
Transmission	$ 64	$ 73	$ 77

Capital Requirements		Payments due in:
(in thousands)		1-3 years	4-5 years	After 5 years
Purchased Power Commitments		$162,861	$82,022	$195,400
Long Term Debt Maturities		-	-	410,350
Operating Leases		1,293	181	-
	Total	$164,154	$82,203	$605,750

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.

InITEM ~~connection with the sale of Vermont Yankee the Company has entered into a power contract to buy 22~~3.5 ~~percent~~LEGAL of the entitlement of the Vermont Yankee generation until 2012. At the same time the Company has entered into a contract with a third party to sell the entire 22.5 percent of the Vermont Yankee entitlement and recover 100 percent of its purchased power contract costs.New Accounting Standards: In June 2001, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). FAS 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. For further information regarding FAS 143 see “Item 8, Financial Statements and Supplementary Data.” In May 2003 the FASB issued Statement of Financial Accounting Standards No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (FAS 150). The Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. For further information regarding FAS 150 see Item 8. Financial Statements and Supplementary Data. PROCEEDINGS

~~ITEM 7A.~~Town ~~QUANTITATIVE~~of ~~AND~~Norwood ~~QUALITATIVE DISCLOSURES ABOUT MARKET RISKInterest Rate Risk~~Dispute: ~~The~~From ~~Company's~~1983 ~~major~~to ~~financial~~1998, ~~market risk~~NEP ~~exposure~~was isthe ~~changing~~wholesale ~~interest~~power ~~rates.~~supplier ~~Changing~~for ~~interest~~the ~~rates~~Town ~~will affect~~of ~~interest~~Norwood. ~~paid~~In onApril 1998, ~~variable~~Norwood ~~rate~~began ~~debt.~~taking Atpower ~~March~~from ~~31,~~another ~~2003~~supplier, ~~2002~~although ~~and~~its ~~2001, the~~contract ~~Company's~~term ~~tax~~with ~~exempt~~NEP ~~variable~~ran ~~rate~~to ~~long-term~~2008. ~~debt~~Pursuant ~~had~~to a ~~carrying~~tariff ~~value~~amendment ~~of approximately~~approved ~~$410~~by ~~million. While~~ the ~~ultimate~~FERC ~~maturity~~in ~~dates~~May 1998, ~~of the underlying~~NEP ~~loan~~has ~~agreements~~been ~~range~~assessing ~~from~~Norwood ~~2015~~a ~~through~~Contract ~~2022,~~Termination ~~this~~Charge ~~debt~~(CTC). isThrough ~~issued~~March 31, in2005, ~~tax exempt~~the ~~commercial~~charges ~~paper~~assessed ~~mode.~~Norwood ~~The~~but ~~various~~not ~~components~~paid ~~that~~amount ~~comprise~~to ~~this~~approximately ~~debt~~$77.7 million. ~~are~~Norwood ~~issued~~made a ~~for~~payment ~~periods~~of ~~ranging~~approximately ~~from~~$20 million ~~one~~in ~~day~~July 2004. toNEP ~~270 days,~~ and Norwood are ~~remarketed~~engaged ~~through remarketing~~in ~~agents~~litigation ~~at the conclusion of each period. The weighted average~~in ~~variable~~state ~~interest~~court ~~rate~~and ~~for~~at the ~~year ended March 31~~FERC, ~~2003,~~as ~~was approximately 1~~follows.52 ~~percent.ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY~~ ~~DATAA. FINANCIAL STATEMENTS~~

~~Report~~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 ~~Independent~~approximately ~~Auditors~~$43.3 million, based on amounts owed through January 31, 2001. Norwood continues to contest the judgment in the Massachusetts Appeals Court.

~~Statements~~FERC ofSection 206 ~~Income~~Challenge. In December 2002, ~~Statements~~Norwood filed a challenge to the CTC rate with the FERC under Section 206 of ~~Retained~~the ~~Earnings~~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 ~~Statements~~set a refund effective date of February 21, 2003, which empowers the FERC to direct NEP to adjust ~~Comprehensive~~Norwood’s ~~Income~~liability for unpaid charges billed after that date in the ~~fiscal~~event ~~year~~that ~~ended~~Norwood’s ~~March~~challenge is 31successful. On June 9, ~~2003~~2004, ~~2002~~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 ~~2001~~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.

~~Balance~~ITEM ~~Sheets~~4. atSUBMISSION ~~March~~OF ~~31,~~MATTERS ~~2003~~TO ~~and~~A ~~2002~~VOTE OF SECURITY HOLDERS

~~Statements~~No matters were submitted to a vote of ~~Cash~~security ~~Flows~~holders ~~for~~during the last quarter of the fiscal year ended March 31, ~~2003~~2005. The Annual Meeting of Stockholders was held on April 20, ~~2002~~2005. ~~and~~By a vote of ~~2001~~3,619,896 shares out of 3,631,013 total shares voted, the following actions were taken:

~~Notes to Financial Statements~~7

To• ~~the~~The ~~Stockholders~~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 ~~Board~~Jeffrey ofA. ~~Directors~~Scott. of• 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.

~~New~~PART ~~England Power Company:~~II

~~New~~The ~~England~~common ~~Power~~stock of NEP is held solely by National Grid USA. There is no public trading market for ~~CompanyStatements~~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 ~~Income~~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”.

			Year Ended March 31,
(In thousands)			2003	2002	2001
Operating revenue, principally from affiliates (Note A)			$514,006	$560,418	$656,272
Operating expenses:
	Fuel for generation		5,209	1,991	7,981
	Purchased electric energy:
		Contract termination and nuclear unit shutdown charges	133,401	174,810	168,639
		Other	59,571	68,675	91,844
	Other operation		49,986	56,769	69,624
	Maintenance		22,666	17,266	31,748
	Depreciation and amortization: (Note A)
	Purchased power contract buyout and nuclear fuel		60,158	58,176	52,670
	Other		37,497	30,601	78,762
	Taxes, other than income taxes (Note K)		18,868	18,183	22,343
	Income taxes (Note G)		45,429	47,593	44,946
		Total operating expenses	432,785	474,064	568,557
Operating income			81,221	86,354	87,715
Other income(expense):
	Allowance for equity funds used during construction		467	1,077	276
	Equity in income of nuclear power companies		4,554	3,332	6,703
	Amortization of goodwill		-	-	(17,905)
	Other income, net		76	791	3,559
		Operating and other income	86,318	91,554	80,348
Interest:

ITEM 6. SELECTED FINANCIAL DATA

~~Interest~~The onfollowing ~~long-term~~table ~~debt~~sets 7forth selected financial information for NEP for the fiscal years ended March 31,~~694~~ 112005,~~434~~ 172004,~~834~~ 2003, 2002 and 2001, respectively. This information has been derived from the financial statements of NEP and should be read together with them.

	Other interest		1,231	3,509	4,883
	Allowance for borrowed funds used during construction		(34)	(163)	(669)
		Total interest	8,891	14,780	22,048
Net income			$ 77,427	$ 76,774	$ 58,300

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.

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


	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		**		**		**		**		**

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

	Year Ended March 31,
(In thousands)	2003	2002	2001
Net Income	$ 77,427	$ 76,774	$ 58,300
Unrealized gain (loss) on securities, net of tax	(120)	35	(145)
Comprehensive income (Note A)	$ 77,307	$ 76,809	$ 58,155

	Year Ended March 31,
(In thousands)	2003	2002	2001
Retained earnings at beginning of period	$ 136,798	$ 60,110	$ 1,415
Net income	77,427	76,774	58,300
Dividends declared on cumulative preferred stock	(82)	(86)	(91)
Gain on redemption of preferred stock	11	-	21
Acquisition adjustment	-	-	465
Retained earnings at end of period	$ 214,154	$136,798	$60,110

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.

~~The~~ITEM ~~accompanying~~7. ~~notes~~MANAGEMENT’S ~~are~~DISCUSSION anAND ~~integral~~ANALYSIS ~~part~~OF ofFINANCIAL ~~these financial~~CONDITION ~~statements. New~~AND ~~England~~RESULTS ~~Power CompanyBalance~~OF ~~Sheets~~OPERATIONS

At March 31 (In thousands)			2003	2002
Assets
Utility plant, at original cost			$ 842,823	$ 909,043
	Less accumulated provisions for depreciation and amortization		245,908	329,927
			596,915	579,116
	Construction work in progress		12,639	7,466
		Net utility plant	609,554	586,582
Goodwill			338,188	338,188
Investments:
	Nuclear power companies, at equity (Note C)		36,749	40,339
	Decommissioning trust funds (Note D)		-	18,810
	Nonutility property and other investments		10,922	11,515
		Total investments	47,671	70,664
Current assets:
	Cash and cash equivalents (including $244,150 and $99,300 with affiliates)		247,678	103,467
	Accounts receivable:
		Affiliated companies	53,112	41,408
		Others (less reserves of $153 and $153)	83,657	67,460
	Fuel, materials, and supplies, at average cost		1,796	6,215
	Prepaid and other current assets		141	1,402
	Regulatory assets – purchased power obligations and accrued Yankee nuclear plant costs		147,200	172,556
		Total current assets	533,584	392,508
Regulatory assets (Note B)			1,377,123	1,297,079
Deferred charges and other assets			14,697	55,184
	Total assets		$2,920,817	$2,740,205

RESTATEMENT OF FINANCIAL STATEMENTS

~~The~~On June 20, ~~accompanying~~2005, ~~notes~~the ~~are~~Company’s anmanagement ~~integral~~concluded ~~part~~it ofhad made ~~these~~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 ~~New~~restatements. ~~England~~See ~~Power~~Note N “Restatement of Previously Issued Financial Statements” in Item 8. ~~CompanyBalance~~Financial ~~Sheets~~Statements and Supplementary Data.

At March 31 (In thousands)			2003	2002
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		214,154	136,798
	Accumulated other comprehensive loss (Note A)		(230)	(110)
		Total common equity	1,018,296	941,060
	Cumulative preferred stock, par value $100 per share (Note I)		1,295	1,436
	Long-term debt (Note J)		410,291	410,285
		Total capitalization	1,429,882	1,352,781
Current liabilities:
	Accounts payable (including $22,798 and $14,059 to affiliates)		71,402	47,358
	Accrued liabilities:
		Taxes	65,311	14,367
		Interest	357	773
		Purchased power obligations and accrued Yankee nuclear plant costs	147,200	172,556
		Other accrued expenses	4,506	3,094
	Dividends payable		19	22
		Total current liabilities	288,795	238,170
Deferred federal and state income taxes			258,492	257,302
Unamortized investment tax credits			8,326	8,795
Accrued Yankee nuclear plant costs (Note D)			212,899	141,869
Purchased power obligations			399,699	513,599
Other reserves and deferred credits			322,724	227,689
Commitments and contingencies (Note D)
Total capitalization and liabilities			$2,920,817	$2,740,205

CRITICAL ACCOUNTING POLICIES

The ~~accompanying~~preparation ~~notes~~of ~~are~~financial anstatements ~~integral~~in ~~part~~conformity with generally accepted accounting principles in the United States of ~~these~~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 ~~New~~estimates ~~England~~are ~~Power~~used, actual amounts could differ from estimated amounts. The following accounting ~~CompanyStatements~~policies represent those that management believes are particularly important to the financial statements and require the use of ~~Cash~~judgment in estimating matters that are inherently uncertain. ~~Flows~~

		Year Ended March 31,
(In thousands)		2003	2002	2001
Operating activities:
Net income		$ 77,427	$ 76,774	$ 58,300
Adjustments to reconcile net income to net cash provided by operating activities:
	Purchased power contract buyout and nuclear fuel amortization	60,158	58,176	52,670
	Other Depreciation and amortization	37,497	30,601	78,762
Amortization of goodwill		-	-	17,905
	Deferred income taxes and investment tax credits, net	2,386	(16,072)	(11,480)
	Allowance for funds used during construction	(501)	(1,240)	(945)
Changes in assets and liabilities:
	Decrease (increase) in accounts receivable, net	(27,901)	16,806	(7,914)
	Decrease (increase) in regulatory assets	(21,538)	145,949	106,224
	Decrease in prepaid and other current assets	5,680	723	30,661
	Decrease in accounts payable	(68,026)	(18,659)	(813)
	Decrease in purchased power contract obligations	(139,256)	(127,069)	(77,039)
	Increase (decrease) in other current liabilities	51,940	(30,327)	30,822
	Increase (decrease) in other non-current liabilities	81,765	(34,171)	(147,847)
	Other, net	42,260	(1,981)	73,202
Net cash provided by operating activities		$ 101,891	$ 99,510	$ 202,508
Investing activities:
Proceeds from sale of generating assets, net		$ 84,300	$ 25,000	$ -
Plant expenditures, excluding allowance for funds used during construction		(41,980)	(46,927)	(56,558)
Other investing activities		226	3,610	(3,270)
Net cash provided by (used in) investing activities		$ 42,546	$(18,317)	$ (59,828)

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 ~~accompanying~~Company ~~notes~~continually ~~are~~assesses anwhether ~~integral~~the ~~part~~regulatory ofassets ~~these~~continue to meet the criteria for ~~financial~~probability ~~statements~~of future recovery. This assessment considers factors such as changes in the ~~New~~regulatory ~~England~~environment, ~~Power~~recent rate orders to other regulated entities under the same jurisdiction, ~~CompanyStatements~~and the status of ~~Cash~~any ~~Flows~~pending –or potential deregulation legislation. If future recovery of costs ~~(continued)~~becomes no longer probable, the assets would be recognized as current-period expense.

		Year Ended March 31,
(In thousands)		2003	2002	2001
Financing activities:
Dividends paid on common stock		$ -	$ -	$(256,463)
Dividends paid on preferred stock		(85)	(86)	(93)
Changes in short-term debt		-	-	(38,500)
Long-term debt – issues		-	-	38,500
Long-term debt – retirements		-	-	(90,575)
Preferred stock – retirements		(141)	-	(110)
	Net cash used in financing activities	$ (226)	$ (86)	$(347,241)
Net increase (decrease) in cash and cash equivalents		$ 144,211	$ 81,107	$(204,561)
Cash and cash equivalents at beginning of period		$ 103,467	$ 22,360	$ 226,921
Cash and cash equivalents at end of period		$ 247,678	$103,467	$ 22,360

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.

Supplementary Information:
Interest paid, less amounts capitalized	$ 7,535	$ 10,734	$ 18,296
Federal and state income taxes paid (refunded)	$ (4,467)	$ 90,810	$ (3,233)
Dividends received from investments at equity	$ 5,984	$ 3,812	$ 13,986

~~New~~Benefit ~~England~~Plans: ~~Power~~The ~~CompanyNotes~~Company tomaintains ~~Financial~~qualified and nonqualified pension plans. The Company also ~~Statements~~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.

~~NOTE~~In Aaddition ~~- SIGNIFICANT ACCOUNTING POLICIESBasis of Presentation: New England Power Company (the Company), a wholly owned subsidiary of National Grid USA, is a Massachusetts corporation qualified~~ to ~~do business in Massachusetts, New Hampshire, Connecticut, Rhode Island, Maine, and Vermont. The Company is subject, for certain purposes, to~~ the ~~jurisdiction~~market ~~of the regulatory commissions of these states (except Connecticut)~~returns, ~~the~~various Securities and Exchange Commission (SEC), under the Public Utility Holding Company Act of 1935 (1935 Act), the Federal Energy Regulatory Commission (FERC), and the Nuclear Regulatory Commission (NRC). The Company’s accounting policies conform to Generally Accepted Accounting Principles (GAAP), including the accounting principles for rate-regulated entities and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Nature of Operations: The Company's business is primarily the transmission of electric energy in wholesale quantities to other ~~electric utilities,~~assumptions principally its distribution affiliates Granite State Electric Company, Massachusetts Electric Company, Nantucket Electric Company, and The Narragansett Electric Company. The Company’s transmission facilities are part of National Grid USA’s transmission operations, which are represented under the name National Grid Transmission USA. In addition, the Company owns a minority interest in one fossil fuel generating unit and sold a minority interest in one jointly owned nuclear generating unit in November 2002. The Company also owns minority equity interests in four nuclear generating companies (Yankees), three of which own generating facilities that are permanently retired and are conducting decommissioning operations and the fourth of which sold its generating assets in July 2002. Goodwill: The Company’s goodwill is primarily the result of two mergers that were accounted for by the purchase method: the merger of New England Electric System and National Grid Transco plc (formerly National Grid Group plc) on March 22, 2002 and the acquisition of Eastern Utilities Associates by National Grid USA (a wholly owned subsidiary of National Grid Transco plc) on April 19, 2000. The approximately $2.1 billion of goodwill that resulted from the transactions was pushed down and reflected on the financial statements of the National Grid USA subsidiaries, including $356 million allocated to the Company. The Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets” (FAS 142) effective April 1, 2001. In accordance with FAS 142, goodwill can no longer be amortized and must be reviewed for impairment at least annually. In the fiscal year ended March 31, 2001, the final year that the Company amortized goodwill, the effect to net income was approximately $18 million. The Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the performance of the annual goodwill impairment test. The result of the annual analysis determined that no adjustment to the goodwill carrying value was required.Use of Estimates: In preparing the financial statements, management is required to make estimates that affect the ~~reported~~pension ~~amounts of assets~~ and ~~liabilities and disclosures of asset recovery and contingent~~other liabilities as of the date of the balance sheets, and revenues and expenses during the reporting period. Actual results could differ from those estimates. Utility Plant: The cost of additions to utility plant and replacements of post-retirement ~~units~~benefit ofexpense ~~property are capitalized. Costs include direct material, labor, overhead~~ and ~~AFDC. Replacement~~measurement of ~~minor~~their ~~items~~respective ~~of utility plant and the cost of current repairs and maintenance are charged to expense~~obligations. ~~Whenever~~ ~~utility plant is retired, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Allowance for Funds Used During Construction (AFDC):~~ The ~~Company~~following ~~capitalizes AFDC as part of construction costs. AFDC represents an allowance for the cost of funds used to finance construction. AFDC~~ is ~~capitalized in "Utility plant" with offsetting noncash credits to "Other income" and "Interest”. This method is in accordance with an established rate-making practice under which~~ a ~~utility~~description isof ~~permitted~~some ~~a return on, and the recovery~~ of, ~~prudently~~those incurred capital costs through their ultimate inclusion in rate base and in the provision for depreciation. The composite AFDC rates were 7.7 percent, 8.1 percent and 3.2 percent for the years ended March 31, 2003, 2002, and 2001, respectively.Depreciation and Amortizationassumptions: ~~The depreciation and amortization expense included in the statements of~~ ~~income is composed of the following:~~

			Year Ended March 31,
(In thousands)			2003	2002	2001
Purchased Power contract buyout and nuclear fuel amortization:
Purchased power contract buyout			$58,490	$54,739	$46,309
Nuclear fuel			1,668	3,437	6,361
Total purchased power contract buyout and nuclear fuel amortization			$60,158	$58,176	$52,670
Other depreciation and amortization:
Depreciation - transmission related			$17,079	$16,238	$15,055
Depreciation - all other			1,011	1,093	5,477
Nuclear decommissioning costs			7,171	2,394	9,901
Amortization:
	Regulatory assets covered by contract termination charges (Note B)		12,236	10,876	48,329
		Total other depreciation and amortization expense	$37,497	$ 30,601	$78,762

	•		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.

~~Depreciation~~Goodwill: isThe ~~provided~~Company ~~annually~~applies onthe aprovisions ~~straight-line~~of ~~basis~~SFAS No. 142, ~~The~~“Goodwill and Other Intangible ~~provision~~Assets” (FAS 142). In accordance with FAS 142, goodwill must be reviewed for ~~depreciation~~impairment asat aleast annually ~~percentage~~and ofbetween ~~weighted~~annual ~~average~~reviews ~~depreciable~~if events occur or circumstances arise indicating that the ~~transmission~~asset ~~property~~may ~~was~~be 2impaired.3 ~~percent~~The ~~for~~Company ~~all~~utilized ~~periods~~a ~~presented.~~discounted ~~Amortization~~cash offlow approach incorporating its most ~~purchase~~recent ~~power~~business ~~contracts~~plan ~~and~~forecasts ~~regulatory~~in ~~assets~~the ~~covered~~performance byof ~~contract~~the ~~termination~~annual goodwill impairment test. The ~~charges~~result ~~(CTC)~~of ~~are~~the inannual ~~accordance~~analysis ~~with~~determined ~~rate~~that ~~settlement~~no ~~agreements~~adjustment to the goodwill carrying value was required.

~~Federal~~Tax ~~and State Income Taxes~~Provision: Income taxes have been computed utilizing the asset and liability approach that requires the recognition of deferred tax assets and liabilities for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities (see Note G).Cash and Cash Equivalents: The Company’s ~~classifies~~tax ~~short-term~~provisions, ~~investments~~including ~~with~~both acurrent ~~maturity at purchase date of 90 days or less as cash equivalents.Comprehensive Income (Loss): Comprehensive income consists of net income~~ and ~~other~~deferred ~~gains and losses affecting common equity that~~components, ~~under generally accepted accounting principles~~ are ~~excluded from net income. For the Company, the components of~~ ~~accumulated~~based ~~other comprehensive income/(loss) consist of unrealized gains and losses~~ on ~~marketable equity investments. For the fiscal years ended March 31~~estimates, ~~2003,~~ ~~2002~~assumptions, calculations and ~~2001~~interpretation of tax ~~expense/(benefit)~~statutes ~~related~~for tothe ~~comprehensive income were~~current ~~approximately $78,000, $22,000~~ and ~~($94,000),~~future ~~respectively.New Accounting~~years ~~Standards:~~in Inaccordance ~~June~~with ~~2001, the FASB~~ SFAS No. ~~143~~ 109, “Accounting for ~~Asset~~Income ~~Retirement Obligations~~Taxes” ~~(FAS 143)~~. ~~FAS~~ ~~143~~Federal ~~provides the~~income ~~accounting~~tax ~~requirements~~returns ~~for~~have ~~retirement~~been ~~obligations~~examined ~~associated~~and ~~with~~all ~~tangible long-lived~~appeals ~~assets. FAS~~and ~~143~~issues ishave ~~effective~~been ~~for~~agreed ~~fiscal~~upon ~~years~~by ~~beginning after June 15, 2002. The Company has evaluated~~ the ~~impact of this standard on its financial~~Internal ~~position~~Revenue Service and ~~results of operations. Based on this evaluation~~ the Company ~~does not~~through ~~believe it has any asset retirement obligations that would have a material effect on its results of operations~~March 22, ~~cash flows and financial position~~2000.

InManagement ~~May~~regularly ~~2003~~makes ~~the~~assessments ~~FASB issued Statement~~ of ~~Financial~~tax Accounting Standards No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (FAS 150). The Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. FAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company is currently evaluating the impact of FAS 150 on its financial position and results of operations.Reclassifications: Certain amounts from prior years have been reclassified in the accompanying financial statements to conform with the 2003 presentation. NOTE B – RATE AND REGULATORY ISSUES AND ACCOUNTING IMPLICATIONSBecause electric utility rates have historically been based on a utility's costs, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. The Company applies the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (FAS 71), which requires regulated entities, in appropriate circumstances, to establish regulatory assets or liabilities, and thereby defer the income statement impact of certain charges or revenues because they are expected to be collected or refunded through future customer billings. In 1997, the Emerging Issues Task Force of the FASB concluded that a utility that had received approval to recover stranded costs through regulated rates would be permitted to continue to apply FAS 71 to the recovery of stranded costs.The Company has received authorization from the FERC to recover through CTCs substantially all of the costs associated with its former generating business not recovered through the divestiture. Additionally, FERC Order No. 888 enables transmission companies to recover their specific costs of providing transmission service. Therefore, substantially all of the Company’s business, including the recovery of its stranded costs, remains under cost-based rate regulation.Under settlement agreements, the Company is permitted to recover costs associated with its former generating investments and related contractual commitments that were not recovered through the sale of those investments (stranded costs). These costs are recovered from the Company’s wholesale customers with whom it has settlement agreements through CTC which the affiliated wholesale customers recover through delivery charges to distribution customers. The recovery of the Company’s stranded costs is divided into several categories. The Company’s unrecovered costs associated with generating plants (nuclear and nonnuclear) and most regulatory assets will be fully recovered through the CTC by the end of 2009 and earn a return onoutcomes ~~equity (ROE)~~relative ~~averaging 9.7 percent. The Company’s obligation related~~ to the above-market cost of purchased power contracts and nuclear decommissioning costs are recovered through the CTC as such costs are actually incurred. As the CTC rate declines, the Company, under certain of the settlement agreements, earns incentives based on successful mitigation of its stranded costs. These incentives supplement the Company’s ROE. In conjunction with the divestiture, the Company transferred to the buyer of its nonnuclear generating business (the buyer) its entitlement to power procured under several long-term contracts in exchange for monthly fixed payments by the Company. These fixed monthly payments by the Company, inclusive of Montaup’s share, average approximately $9 million per month through December 2009 toward the above-market cost of those contracts. The net present value of these fixed monthly payments is recorded as a liability with an equal balance recorded in regulatory assets representing the future collection of the liability from rate payers. At March 31, 2003 and 2002, the net present value is approximately $507 million and $659 million, respectively. Under a 1997 purchased power transfer agreement, USGen New England, Inc. ("USGen") purchased from the Company an entitlement to approximately 1,100 megawatts of power procured under long-term contracts. In connection with this transfer agreement, the Company agreed to pay USGen a fixed amount for the above-market cost of the purchased power. The present value of this obligation is approximately $0.4 billion at March 31, 2003 and is recorded as a liability on the balance sheet, offset in full by a regulatory asset. In the event that USGen, which has recently encountered financial ~~difficulty, defaults~~statement ~~on the payments of these contracts the Company would assume the~~tax ~~obligation,~~provisions ~~in turn, eliminating the fixed obligation to USGen. In that instance the Company would remove the $0.4 billion liability from its balance sheet~~ and ~~the~~adjusts ~~corresponding regulatory asset. The Company believes that~~ the ~~impact~~ ontax ~~results~~provisions ~~of operations would not be material as the above-market portion of the contracts would continue to be passed to customers through CTCs. As indicated~~ in ~~Management's Discussion and Analysis of Financial Condition and Results of Operations,~~ the ~~Company~~period ~~made~~when afacts ~~$77~~become ~~million payment in November 2002 to assign and permanently release the Company from future obligations under one purchased power agreement with USGen~~final. ~~The $77 million payment is recoverable~~ ~~from customers through CTCs. As a result of applying FAS 71, the~~ ~~Company has recorded a regulatory asset for the costs that are recoverable from~~ customers through the CTC. At March 31, 2003 and 2002 this amounted to approximately $1.3 billion and $1.4 billion, respectively, including $0.8 billion and $1.0 billion, respectively, related to the above-market costs of purchased power contracts, $0.3 billion and $0.2 billion, respectively, related to accrued Yankee nuclear plant costs, and $0.2 billion and $0.2 billion, respectively, related to other net CTC regulatory assets.Pension: The Company has recognized an additional minimum pension liability of $94 million on its balance sheet in other reserves and deferred credits to reflect its under funded pension obligation. Due to the nature of its rate plan the Company has recorded a regulatory asset representing the future collection of the liability from rate payers. NOTE C – ACCOUNTING FOR NUCLEAR INVESTMENTSYankee Nuclear Power Companies: The Company has minority interests in four generating nuclear companies (the Yankees). These ownership interests are accounted for on the equity method. Three of the Yankees own nuclear generating units that have been permanently retired and are conducting decommissioning operations and one sold its nuclear generating unit in July 2002. The Company has power contracts with each of the decommissioning Yankees that require the Company to pay an amount equal to its share of total fixed and operating costs of the plant plus a return on equity. The Company’s share of the expenses of the Yankees is accounted for in “Purchased electric energy” on the income statement. The following table summarizes financial information furnished by the Yankees:

			Year Ended March 31,
(In thousands)			2003	2002	2001
Operating revenue			$ 283,609	$ 284,663	$ 291,628
Net income			$ 20,828	$ 14,711	$ 29,589
Company’s equity in net income			$ 4,554	$ 3,332	$ 6,703
Net plant			2,132	143,182	160,701
Other assets			1,608,191	1,812,032	1,893,733
Liabilities and debt			(1,447,168)	(1,775,130)	(1,855,775)
Net assets			$ 163,155	$ 180,084	$ 198,659
Company’s equity in net assets			$ 36,749	$ 40,339	$ 46,474
Company's purchased electric energy:
	Vermont Yankee	$ 39,804		$ 33,031	$ 31,899
	All other Yankees	$ 21,778		$ 24,420	$ 21,616

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

At March 31, 2003, approximately $6 million of undistributed earnings of the nuclear power companies were included in the Company’s retained earnings.Seabrook 1 Nuclear Generating Unit: The Company sold its 10 ~~percent non-operating ownership interest in the Seabrook 1 Nuclear Generating~~ Unit (Seabrook) in November 2002. Prior to the sale of Seabrook the Company’s share of expenses for the unit were accounted for in “Other operation” and “Maintenance” expenses on the income statement.NOTE D – COMMITMENTS AND CONTINGENCIESDecommissioning Nuclear Units: Three of the Yankees in which the Company has a minority interest own nuclear generating units that have been permanently retired and are conducting decommissioning operations. These three units are as follows:

	The Company’s Investment as of March 31, 2003			Future Estimated Billings to the Company
Unit	%	$(millions)	Date Retired	$(millions)
Yankee Atomic	34.5	0.3	Feb 1992	78
Connecticut Yankee	19.5	11	Dec 1996	70
Maine Yankee	24.0	13	Aug 1997	103

With respect to each of these units, NEP has recorded a liability and a regulatory asset reflecting the estimated future decommissioning billings from the companies. In a 1993 decision, the FERC allowed Yankee Atomic to recover its undepreciated investment in the plant, including a return on that investment, as well as unfunded nuclear decommissioning costs and other costs. Maine Yankee and Connecticut Yankee recover their prudently incurred costs, including a return, in accordance with settlement agreements approved by the FERC in May 1999 and July 2000, respectively. The Company’s share of the decommissioning costs is accounted for in "Purchased electric energy" on the income statement.Future estimated billings are decommissioning cost estimates. These estimates include the projected costs of decontaminating the units as required by the Nuclear Regulatory Commission, dismantling the units, spent fuel storage, security, and liability and property insurance, as well as other costs. Such costs reflect estimates of total decommissioning costs which are recovered in rates regulated by the FERC. The decommissioning costs that are actually incurred by the Yankees may exceed the estimated amounts, perhaps substantially. For example, in light of new regulatory requirements security costs have already increased beyond previous estimates. Also, cost estimates assume the availability of permanent repositories for both low-level and high-level nuclear waste by 2023. Additionally costs may increase if the Yankees must replace decommissioning operations contractors who fail to perform in accordance with their obligations (see Bechtel Dispute below). In the third quarter of fiscal 2003 the Yankees increased their aggregate decommissioning estimates to reflect, projected future security, insurance cost increases and other expenses. Based on those estimates the Company's share of the additional cost is approximately $121 million. Under settlement agreements, the Company is permitted to recover prudently incurred decommissioning costs through CTCs.Decommissioning Collections: Each of the Yankees has established a decommissioning trust fund, or escrow fund, into which its owners make payments to meet the projected costs of decommissioning. Under its power contract with each Yankee, the Company is liable for its pro rata share of their decommissioning costs. In addition, a Maine statute provides that if both Maine Yankee and its decommissioning trust fund have insufficient assets to pay to decommission the plant, the owners of Maine Yankee are jointly and severally liable for the shortfall. The Company has been paying and recording its portion of projected decommissioning costs for the plants owned by the Yankees consistent with its rate recovery. Maine Yankee and Connecticut Yankee are required to make filings with the FERC regarding their costs within the next 14 months. Yankee Atomic filed for a rate increase which the FERC allowed to become effective June 5, 2003, subject to refund. Subsequently Yankee Atomic has resumed making decommissioning collections. DOE Dispute: The Nuclear Waste Policy Act of 1982 establishes that the federal government (through the DOE) is responsible for the disposal of spent nuclear fuel. In a lawsuit brought against the DOE by numerous utilities and state regulatory commissions, the U.S. Court of Appeals for the District of Columbia ruled in 1997 that the DOE was obligated to begin disposing of utilities’ spent nuclear fuel by January 1998. The DOE failed to meet this deadline. Many owners of nuclear power plants, including the Yankees filed claims for money damages in the U.S. Court of Federal Claims for the costs associated with the DOE’s failure to begin to take fuel in 1998. The court held that the DOE is liable for such failure in October 1998. The Yankees have filed a further action against the DOE to determine the level of damages. That action is pending. As an interim measure until the DOE meets its contractual obligations to dispose of the spent fuel, the Yankees have proceeded with construction of independent spent fuel storage installations ("ISFSIs") located at the plant sites. Yankee Atomic and Maine Yankee have commenced moving their spent nuclear fuel to their respective ISFSIs. Connecticut Yankee has not yet begun the process of moving spent nuclear fuel. The Yankees expect to complete the process of moving spent nuclear fuel to their respective ISFSIs by December 2004.Bechtel Dispute: Connecticut Yankee has notified Bechtel Power Corporation, its decommissioning operations contractor, that it is in default of its obligations and that Connecticut Yankee intends to terminate its contract, subject to Bechtel’s right to cure. Bechtel has filed a proceeding in Connecticut Superior Court against Connecticut Yankee alleging breach of contract and other grounds. Connecticut Yankee intends to assert claims against Bechtel and to litigate its claims and defend against Bechtel's claims vigorously. These developments may delay the progress of decommissioning the Connecticut Yankee power plant and may increase the Company’s costs associated with it.Divested Nuclear Units: Seabrook: The Company previously held a 10 percent non-operating ownership interest in the Seabrook Nuclear Generating Station (Seabrook). As part of a consortium of joint owners, the Company sold its interest in Seabrook to FPL Energy Seabrook LLC (FPL) on November 1, 2002. Pursuant to the transaction, FPL assumed the decommissioning liability and trust fund for the plant including the Company's share of both. Net of closing adjustments, the Company's share of the proceeds from the sale of Seabrook was approximately $84 million following its $5 million top-off payment to the decommissioning trust fund. Ninety-eight percent of the proceeds from the sale in excess of related expenses and the Company's post-1995 investment will be credited to the Company's customers through CTCs. The Company’s share of expenses for Seabrook prior to November 1, 2002 is accounted for in "Other operation" and "Maintenance" expenses on the income statement. Vermont Yankee Nuclear Power Corporation: The Company has a 23.9 percent equity investment in the Vermont Yankee Nuclear Power Corporation (Vermont Yankee). Vermont Yankee was formerly the owner of Vermont Yankee Nuclear Generating station. On July 30, 2002, Vermont Yankee completed the sale of Vermont Yankee Nuclear Generating Station to Entergy Vermont Yankee LLC (ENVY) for approximately $180 million. The Company’s portion of the sale price was approximately $43 million for its 23.9 percent ownership interest in Vermont Yankee. As part of the transaction, ENVY assumed the decommissioning liability for the plant. Vermont Yankee received regulatory approval from the SEC on May 13, 2003 to distribute the net proceeds from the sale of the plant. The proceeds will be distributed through a series of dividend payments and stock buybacks. The majority of the Company’s net proceeds from the sale will be credited to its customers through CTCs.Plant Expenditures: The Company’s utility plant expenditures are estimated to be approximately $64 million for 2004. At March 31, 2003, substantial commitments had been made relative to future planned expenditures.Hydro-Quebec Interconnection: Three affiliates of the Company were created to construct and operate transmission facilities to transmit power from Hydro-Quebec to New England. Under support agreements entered into at the time these facilities were constructed, the Company agreed to guarantee a portion of the project debt. At March 31, 2003, the Company had guaranteed approximately $18 million of project debt, including $3 million originally guaranteed by Montaup, with terms through 2015. The Company’s rights and obligations under its support agreements were transferred to the purchaser of its nonnuclear generation, but the Company retained Montaup’s rights and obligations under its support agreement. The Company remains an obligor under the support agreements for the portion of the rights it transferred until 2020. Costs associated with these support agreements are recoverable through the Company’s transmission rates.Hazardous Waste: The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. A number of states, including Massachusetts, have enacted similar laws.The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. The Company currently has in place an internal environmental audit program and an external waste disposal vendor audit and qualification program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products.The Company has been named as a potentially responsible party (PRP) by either the United States Environmental Protection Agency or the Massachusetts Department of Environmental Protection for several sites at which hazardous waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against the Company regarding hazardous waste cleanup. The Company is currently aware of other possible hazardous waste sites, and may in the future become aware of additional sites, that it may be held responsible for remediating. Some of these sites relate to the disposal of ash from fossil fuel generating plants formerly owned by the Company.Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. The Company has recovered amounts from certain insurers, and, where appropriate, intends to seek recovery from other insurers and from other PRPs, but it is uncertain whether, and to what extent, such efforts will be successful. The Company is currently recovering certain environmental cleanup costs in rates. The Company believes that hazardous waste liabilities for all sites of which it is aware are not material to its financial position.Town of Norwood Dispute: From 1983 until 1998, the Company was the wholesale power supplier for Norwood. In April 1998, Norwood began taking power from another supplier. Pursuant to a tariff amendment approved by the Federal Energy Regulatory Commission (FERC) in May 1998, the Company has been assessing Norwood a contract termination charge (CTC). Through March 31, 2003, the charges assessed Norwood amount to approximately $59 million, all of which remain unpaid. The Company filed a collection action in Massachusetts Superior Court (Superior Court). The Superior Court deferred action until the various appeals were decided. In March 2001, the Superior Court ordered Norwood to pay the Company approximately $27 million including interest, and affirmed Norwood’s obligation to make monthly CTC payments to the Company of approximately $600,000, plus interest. Norwood appealed the order in April 2001. Pending the appeal, Norwood entered into a consent order to establish a segregated account for the benefit of the Company in the amount of approximately $14 million and to make regular additions to the account. As of March 31, 2003, Norwood reported that the account has grown to approximately $23 million. Oral arguments on Norwood's appeal took place in March 2003 and a decision is expected soon. On December 23, 2002, Norwood filed a complaint with the FERC, challenging the CTC on multiple grounds. In a draft order released on or about June 25, 2003, FERC granted NEP's motion to dismiss those portions of Norwood's complaint under Section 206 of the Federal Power Act that Norwood previously litigated before FERC and the federal district court, and set down for hearing Norwood's challenge to the factors that are used to calculate the CTC rate. In so doing, the FERC set a refund effective date of February 21, 2003 and referred the matter initially to a FERC settlement judge, consistent with its normal procedures. The draft order is subject to further modification by FERC before it is issued in final form. For further information regarding the Town of Norwood dispute see Item 3, Legal Proceedings.Millstone Unit 3: In November 1999, the Company entered into an agreement with NU to settle certain claims. Among other things, the settlement agreement provided for NU to include the Company’s 16.2 percent ownership interest in Millstone Unit 3 in an auction of NU’s share of the unit. Upon the closing of the sale, the Company was to receive a fixed amount, regardless of the actual sale price. In March 2001, the Millstone units were sold, including the Company’s interest in Millstone 3, for $1.3 billion. In accordance with the settlement agreement, the Company was paid approximately $27.9 million, from which the Company paid approximately $5.8 million to increase the decommissioning trust fund.Regulatory authorities from Rhode Island, New Hampshire, and Massachusetts have expressed intent to challenge the reasonableness of the settlement agreement, taking the position that the Company would have received approximately $140 million of sale proceeds if there had been no agreement with NU. In the event that one or more of the states proceed with such a challenge, the dispute will be resolved by the FERC. The Company believes it has a strong argument that it acted prudently, as the amount it received under the settlement agreement was the highest sale price for a nuclear unit at the time the agreement was reached.Contracts for the Purchase of Electric Power: The Company has contracts for the purchase of electric power. The Company’s commitments for future fiscal periods, under these long-term contracts as of March 31, 2003, is as follows (in thousands): 2004, $67 million; 2005, $56 million; 2006, $40 million; 2007, $42 million: and 2008 and thereafter $239 million.In connection with the sale of Vermont Yankee, the Company entered into a power contract to buy 22.5 percent of the entitlement of the Vermont Yankee generation until 2012. At the same time the Company has entered into a contract with a third party to sell the entire 22.5 percent of the Vermont Yankee entitlement and recover 100 percent of its purchased power contract costs.NOTE E - SEGMENTS The Company's reportable segments are electric transmission and electric other. The Company is engaged principally in the business of electric power transmission. Certain information regarding the Company's segments is set forth in the following table. General corporate expenses, property common to both segments and depreciation on such common property have been allocated to the segments based on labor or plant using a percentage derived from total labor or plant dollars charged directly to certain operating expense accounts or certain plant accounts. General corporate expenses include the cost of the services furnished by National Grid USA Service Company, Inc., an affiliated service company operating pursuant to the provisions of Section 13 of the 1935 Act. Assets allocated to the electric transmission and electric other segments include net utility plant, materials and supplies, and certain regulatory and other assets. Corporate assets consist primarily of other property and investments, cash, restricted cash, and unamortized debt expense.

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.

	Year Ended March 31,
(In millions)	2003			2002
	Electric Transmission	Electric Other	Total	Electric Transmission	Electric Other	Total
Operating Revenues	$164	$350	$514	$159	$401	$560
Operating Income before Income taxes	73	52	125	68	63	131
Depreciation and Amortization	18	68	86	17	61	78
Amortization of Stranded Costs	-	12	12	-	11	11

RESULTS OF OPERATIONS

	Total Assets
(In millions)	2003	2002
Transmission	$1,076	$997
Electric Other	1,551	1,569
Corporate Assets	294	174
Total	$2,921	$2,740

EARNINGS

~~NOTE~~Net Fincome -for ~~PENSION~~the ~~AND~~year ~~POSTRETIREMENT~~ended ~~BENEFIT PLANS OTHER THAN PENSIONSPension Plan: The Company participates with certain other subsidiaries of National Grid USA in a noncontributory~~March 31, ~~defined~~2005 ~~benefit plan~~was ~~covering~~not ~~substantially~~significantly ~~all~~different ~~employees~~from of the ~~Company. The plan provides pension benefits based on the employee's compensation during the five years~~ prior ~~to retirement~~year. ~~Absent unusual circumstances, the Company’s funding~~ ~~policy~~Affecting ~~is to contribute each year the~~ net ~~periodic~~income ~~pension~~during ~~cost for that year. However,~~ the ~~contribution~~fiscal ~~for any~~ year ~~will~~was ~~not~~one betime ~~less~~tax ~~than~~adjustments ~~the~~that ~~minimum contribution~~resulted ~~required~~from settlement byof ~~federal law or greater than the maximum~~ tax~~-deductible amount.Net~~ ~~pension~~audits, ~~cost~~partially ~~for~~offset ~~the~~by ~~years~~interest ~~ended~~costs ~~March~~associated ~~31,~~with ~~2003,~~these ~~2002~~settlements and ~~2001~~reduced ~~included~~stranded ~~the~~cost ~~following components:~~recoveries.

			Year Ended March 31,
(In thousands)			2003	2002	2001
Service cost - benefits earned during the period			$ 729	$ 809	$ 482
Plus (less):
	Interest cost on projected benefit obligation		8,954	8,729	8,381
	Return on plan assets at expected long-term rate		(12,500)	(12,789)	(12,440)
	Amortization of prior service cost		209	195	-
		Benefit income	$ (2,608)	$(3,056)	$ (3,577)
Special termination benefits not included above			$ -	$ 1,339	$ -

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.

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

(In millions)	2003	2002
Change in benefit obligation:
Benefit obligation at beginning of period	$ 1,074	$ 1,055
Service cost	15	14
Interest cost	78	76
Actuarial (gain)/loss	173	(8)
Benefits paid	(82)	(76)
Special termination benefits	-	13
Benefit obligation at end of period	1,258	1,074
Reconciliation of change in plan assets:
Fair value of plan assets at beginning of period	1,053	1,082
Actual return on plan assets during year	(110)	39
Company contributions	8	8
Benefits paid from plan assets	(82)	(76)
Fair value of plan assets at end of period	869	1,053
Funded status	(389)	(21)
Unrecognized actuarial loss	646	261
Unrecognized prior service cost	17	19
Net amount prepaid	274	259
Amounts recognized on the balance sheet consist of:
Prepaid benefit cost	-	346
Accrued benefit liability	(255)	(90)
Intangible asset	18	-
Regulatory assets	92	-
Accumulated other comprehensive income	419	3
Net amount recognized on the balance sheet	$ 274	$ 259

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.

		March 31,
		2003	2002
Assumptions used to determine pension cost:
	Discount rate	6.25%	7.50%
	Average rate of increase in future compensation level
	Union	4.00%	4.00%
	Non-Union	5.25%	5.25%
	Expected long-term rate of return on assets	8.50%	8.75%

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.

~~Plan~~Operating ~~assets~~revenue ~~are composed primarily of equity and fixed income securities.Additional Minimum Liability (AML): Statement of Financial Accounting Standards 87 “Employers’ Accounting~~ for ~~Pensions” states~~ ~~that~~fiscal ifyear aended ~~pension plans~~March ~~' accumulated benefit obligation (ABO) exceeds the fair value of plan assets~~31, ~~the employer~~2004 ~~shall~~decreased ~~recognize~~approximately in$54 million ~~the statement of financial position a liability that~~compared ~~is at least equal~~ to the ~~unfunded ABO~~ ~~with~~prior ~~an offsetting charge to other comprehensive income~~year. ~~Due~~The ~~to the~~primary ~~severe~~reason ~~downturn~~for in the ~~capital markets the~~decrease ~~Company's~~was ~~ABO at~~reduced ~~March~~sales ~~31, 2003 is greater than the fair value~~ of ~~plan~~power ~~assets. As~~received ~~such, the Company has recognized an~~from ~~additional~~Vermont ~~minimum~~Yankee ~~pension liability of $94 million on its balance sheet in other reserves~~ and ~~deferred~~Seabrook ~~credits~~during ~~reflecting~~ the ~~under funded~~ ~~pension~~fiscal ~~obligation~~year. ~~However,~~ ~~due~~The todecrease ~~the~~is ~~nature~~also ofrelated ~~its~~to ~~rate plan the~~reduced ~~Company has not charged other comprehensive income but~~CTC ~~has~~revenue ~~instead~~due ~~recorded~~to afully ~~regulatory~~reconciling ~~asset. If~~true-up inmechanisms ~~the future, capital markets recover such~~ that ~~the~~allow ~~fair value of plan assets is once again greater than~~ the ~~ABO,~~ ~~the additional minimum pension liability will be removed from the~~ Company~~'s balance~~ ~~sheets.Postretirement~~to ~~Benefit~~adjust ~~Plans Other than Pensions~~revenues ~~(PBOPs):~~proportionately ~~The~~with ~~Company~~correlating ~~provides health care and life insurance coverage to eligible retired employees~~expenses. ~~Eligibility~~In isaddition, ~~based~~reduced onmitigation ~~certain~~incentives ~~age~~under ~~and length of~~the ~~service~~CTC ~~requirements~~contributed ~~and in some cases retirees must contribute~~ to the ~~cost~~reduction ~~of their~~in ~~coverage.The~~operating ~~Company's total cost of PBOPs for the years ended~~revenue. ~~March 31, 2003, 2002 and 2001 included the following components:~~

			Year Ended March 31,
(In thousands)			2003	2002	2001
Service cost - benefits earned during the period			$ 221	$ 225	$ 210
Plus (less):
	Interest cost on projected benefit obligation		3,994	3,434	3,337
	Return on plan assets at expected long-term rate		(3,841)	(3,721)	(3,537)
	Amortization of prior service cost		(12)	-	-
	Amortization of net loss		395	120	-
		Benefit cost	$ 757	$ 58	$ 10
Special termination benefits not included above			$ -	$ 61	-

OPERATING EXPENSES

~~The~~Purchased ~~following~~electric ~~provides~~energy afor ~~reconciliation~~the offiscal ~~benefit~~year ~~obligations~~ended ~~and~~March 31, ~~plan assets~~2005 atincreased ~~March~~approximately ~~31:~~$2 million

(In millions)	2003	2002
Change in benefit obligation:
Benefit obligation at beginning of period	$ 53	$47
Interest cost	4	3
Actuarial loss	14	7
Benefits paid	(4)	(4)
Benefit obligation at end of period	67	53
Reconciliation of change in plan assets:
Fair value of plan assets at beginning of period	41	41
Actual return/(loss) on plan assets during year	(4)	1
Company contributions	3	3
Benefits paid from plan assets	(4)	(4)
Fair value of plan assets at end of period	36	41
Funded status	(31)	(12)
Unrecognized actuarial loss	37	16
Net amount prepaid	$ 6	$ 4

			March 31,
(In thousands)			2003	2002
Assumptions used to determine postretirement benefit cost:
	Discount rate		6.25%	7.50%
	Expected long-term rate of return on assets		8.35%	8.43%
	Health care cost rates:
		2001	N/A%	N/A%
		2002	N/A%	10.00%
		2003	9.00%	9.00%
		2004	8.00%	5.00%
		2005	7.00%	5.00%
		2006	6.00%	6.00%
		2007	5.00%	5.00%
		2008+	5.00%	5.00%

~~The~~compared ~~assumptions~~with ~~used in~~ the ~~health~~same ~~care~~period ~~cost trends have a significant effect on the amounts reported. A one percentage point change~~ in the assumed rates would increase the accumulated postretirement benefit obligation (APBO) as of March 31, 2003 by approximately $8 million or decrease the APBO by approximately $7 million, and increase or decrease the net periodic cost for 2004 byprimarily ~~approximately~~due ~~$500,000.The Company generally makes contributions~~ to ~~the~~increased ~~plans~~nuclear ~~equal to the annual allowable tax-deductible amount.NOTE~~decommissioning Gcosts –in ~~FEDERAL AND STATE INCOME TAXES The Company and other~~2005 ~~subsidiaries~~compared ~~participate~~ with ~~National~~the ~~Grid~~prior ~~General~~year ~~Partnership,~~partially aoffset ~~wholly~~by ~~owned subsidiary~~reductions ~~of National Grid Transco plc,~~ in ~~filing~~other ~~consolidated~~purchased ~~federal~~power ~~income tax returns~~expense. ~~The Company's income tax provision is calculated on a separate~~ ~~return basis. Federal income tax returns have been examined and all appeals and~~ ~~issues have been agreed upon by the Internal Revenue Service and the Company~~ ~~through 1996.Total income taxes in the statements of income are as follows:~~

	Year Ended March 31,
(In thousands)	2003	2002	2001
Income taxes charged to operations	$45,429	$47,593	$44,946
Income taxes charged (credited) to "Other income"	1,443	1,694	(52)
Total income taxes	$46,872	$49,287	$44,894

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.

~~Total~~Operation ~~income~~and ~~taxes~~maintenance expense for the fiscal year ended March 31, as2005 ~~shown~~decreased ~~above~~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, ~~consist~~offset by the resumption of support payments under the ~~following~~HQ contracts. ~~components:~~

	Year Ended March 31,
(In thousands)	2003	2002	2001
Current income taxes	$44,486	$ 65,359	$ 56,374
Deferred income taxes	2,855	(15,555)	(1,111)
Investment tax credits, net	(469)	(517)	(10,369)
Total Income Taxes	$46,872	$49,287	$44,894

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.

~~Since~~Amortization ~~1998,~~of ~~the~~stranded ~~Company~~costs ~~has~~for ~~been~~the ~~amortizing~~fiscal ~~previously~~year ~~deferred investment~~ended ~~tax~~March 31, ~~credits~~2005 ~~(ITC)~~decreased ~~related~~approximately to$3 million ~~generation~~compared ~~investments~~with ~~over~~ the ~~CTC recovery~~same period. ~~Unamortized ITC related to generating units divested~~ in ~~1998 and 2001 were credited to other income pursuant to federal tax law~~2004. ~~Previously recognized~~The ~~ITC~~decrease ~~related~~was toa ~~transmission~~result ~~facilities~~of ~~are~~the ~~amortized~~scheduled ~~over their~~changes ~~estimated~~in ~~productive~~amortization ~~lives.Total~~in ~~income~~accordance ~~taxes,~~with asthe ~~shown~~annual ~~above,~~CTC ~~consist~~filings. ~~of federal and state components as follows:~~

	Year Ended March 31,
(In thousands)	2003	2002	2001
Federal income taxes	$41,039	$41,018	$ 38,350
State income taxes	5,833	8,269	6,544
Total Income Taxes	$46,872	$49,287	$44,894

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.

~~With~~Other ~~regulatory~~depreciation ~~approval~~and ~~from~~amortization ~~the~~expense ~~FERC,~~for the ~~Company~~fiscal ~~has~~year ~~adopted comprehensive~~ended ~~interperiod~~March 31, ~~tax~~2005 ~~allocation (normalization) for temporary book/tax~~increased ~~differences.Total~~approximately ~~income~~$1 million ~~taxes~~compared ~~differ~~with ~~from~~ the ~~amounts~~prior ~~computed~~year ~~by applying~~due ~~the federal statutory tax rates~~ to ~~income~~an ~~before~~increase ~~taxes.~~in ~~The~~plant ~~reasons for~~expenditures. ~~the differences are as follows:~~

	Year Ended March 31,
(In thousands)	2003	2002	2001
Computed tax at statutory rate	$43,505	$44,121	$36,118
Increases (reductions) in tax resulting from:
Amortization of investment tax credits	(305)	(336)	(7,762)
State income taxes, net of federal income tax benefit	3,791	5,375	4,254
Rate recovery of deficiency in deferred tax reserves	1,103	1,007	4,339
Amortization of goodwill	-	-	6,267
Prior year tax adjustment	-	-	773
Millstone 3 sale	-	-	1,787
All other differences	(1,222)	(880)	(882)
Total income taxes	$46,872	$49,287	$44,894

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.

~~The~~Other ~~Company adopted SFAS No. 109, “Accounting for Income Taxes”, which requires recognition of deferred income~~ taxes ~~for~~decreased ~~temporary differences~~approximately ~~that~~$1 million ~~are~~and ~~reported~~$2 million ~~in different years~~ for ~~financial reporting and tax purposes using~~ the ~~liability~~years ~~method.~~ended ~~Under the liability method~~March 31, ~~deferred tax~~2005 ~~liabilities~~and ~~or assets are computed using the tax rates that will be in effect when temporary differences reverse. Generally~~2004, ~~for regulated companies~~respectively, ~~the change~~compared inwith ~~tax~~prior ~~rates~~years ~~may~~primarily ~~not~~due beto ~~immediately~~reductions ~~recognized~~ in ~~operating~~property ~~results~~taxes. ~~because of rate-making treatment and provisions in the Tax Reform Act of~~ ~~1986.The following table identifies the major components of total~~ ~~deferred income taxes:~~

At March 31 (In millions)			2003	2002	2001
Deferred tax asset:
	Plant related		$ 66	$ 67	$ 67
	Investment tax credits		3	3	4
	All other		42	37	30
			111	107	101
Deferred tax liability:
	Plant related		32	(211)	(211)
	All other, principally regulatory assets		(401)	(153)	(162)
			(369)	(364)	(373)
		Net deferred tax liability	$(258)	$(257)	$(272)

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.

~~There~~Equity ~~were~~in noincome valuation allowances for deferred tax assets deemed necessary at March 31, 2003, 2002 and 2001, respectively.NOTE H - SHORT-TERM BORROWINGSAt March 31, 2003 and 2002 the Company had no short-term debt outstanding. The Company has regulatory approval to issue up to $375 million of ~~short-term~~nuclear ~~debt.~~power 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~~remained ~~interest~~relatively atunchanged aduring ~~rate designed to approximate~~ the ~~cost~~fiscal ~~of outside short-term borrowings. Companies that invest in the pool~~year ~~share~~ended ~~the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice.At~~ March 31, ~~2003~~2005 ~~and~~compared ~~2002 the Company had lines of credit and standby bond purchase facilities~~ with ~~banks totaling $419 million and $456 respectively, which are available to provide liquidity support for $410 million of~~ the ~~Company’s~~same ~~long-term~~period ~~bonds~~ in tax-exempt commercial paper mode, and for other corporate purposes. The Company's line of credit expires and is renewed each December. The Company's standby bond purchase facility expires and is renewed each September. There were no borrowings under these lines of credit at March 31, 2003. Fees are paid on the ~~lines~~prior ~~and facilities in lieu of compensating balances~~year.~~NOTE~~ IIt -decreased ~~CUMULATIVE~~approximately ~~PREFERRED STOCKA summary of cumulative preferred stock at March 31,~~$3 ~~2003, 2002 and 2001, is as follows (in thousands of dollars except for share~~ ~~data):~~

	Shares Outstanding		Amount		Dividends Declared
	2003	2002	2003	2002	2003	2002
$100 par value 6.00% Series (a)	12,950	14,361	$1,295	$1,436	$82	$86

At March 31 (In thousands)
Series	Rate %	Maturity	2003	2002	2001
Pollution Control Revenue Bonds:
CDA (a)	Variable	October 15, 2015	$ 38,500	$ 38,500	$ 38,500
MIFA 1 (b)	Variable	March 1, 2018	79,250	79,250	79,250
BFA 1 (c)	Variable	November 1, 2020	135,850	135,850	135,850
BFA 2 (c)	Variable	November 1, 2020	50,600	50,600	50,600
MIFA 2 (b)	Variable	October 1, 2022	106,150	106,150	106,150
Unamortized discounts			(59)	(65)	(71)
Total long-term debt			$ 410,291	$ 410,285	$ 410,279

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.

~~(a)~~Other ~~CDA~~income =net ~~Connecticut~~remained ~~Development~~relatively ~~Authority~~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.

~~(b)~~Interest ~~MIFA~~expense =increased ~~Massachusetts~~approximately ~~Industrial~~$5 million ~~Finance~~for ~~Authority(c) BFA = Business Finance Authority of~~ the ~~State~~fiscal ofyear ~~New~~ended ~~HampshireAt~~ March 31, ~~2003,~~2005 ~~interest~~compared ~~rates~~with on the ~~Company's~~prior ~~variable~~year ~~rate~~primarily ~~long-term~~due ~~bonds ranged from 1.1 percent~~ to ~~1.45~~increased ~~percent. There~~interest ~~are~~rates noon ~~payments or sinking fund requirements due in 2004 through 2007.At March 31, 2003,~~ the Company'’s variable rate long-term debt ~~had a carrying value~~ and ~~fair~~interest ~~value~~charges ~~of approximately $410 million. The fair value of debt~~ that ~~re-prices~~resulted ~~frequently~~from ata ~~market~~tax ~~rates~~appeal ~~approximates carrying value~~settlement.~~NOTE K - SUPPLEMENTARY INCOME STATEMENT~~ ~~INFORMATIONAdvertising expenses, expenditures for research and~~ ~~development, and rents were not material and there were no royalties paid in the~~ ~~years ended March 31, 2003, 2002 or 2001. Taxes, other than income taxes, charged to operating expenses are set forth by class as follows:~~

	Year Ended March 31,
(In thousands)	2003	2002	2001
Municipal property taxes	$16,800	$16,045	$19,334
Federal and state payroll and other taxes	2,068	2,138	3,009
Total Taxes other than Income Taxes	$18,868	$18,183	$22,343

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.

~~Transactions~~LIQUIDITY ~~between~~AND ~~the~~CAPITAL ~~Company and other affiliated companies for~~RESOURCES ~~sales of electric energy and other sales amounted to approximately $324 million,~~ ~~$354 million and $386 million for the years ended March 31, 2003, 2002 and 2001,~~ ~~respectively.National Grid USA Service Company, Inc., an affiliated~~ service company operating pursuant to the provisions of Section 13 of the 1935 Act, furnished services to the Company at the cost of such services. These costs amounted to approximately $46 million, $43 million and $43 million including capitalized construction costs of $10 million, $15 million and $19 million for the years ended March 31, 2003, 2002 and 2001, respectively.NOTE L – SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

(In thousands)	Quarter Ended June 30, 2002	Quarter Ended Sept. 30, 2002	Quarter Ended Dec. 31, 2002	Quarter Ended March 31, 2003
Operating revenue	$143,488	$134,344	$134,463	$101,711
Operating income	$ 21,891	$ 20,553	$ 23,105	$ 15,672
Net income	$ 20,398	$ 20,837	$ 21,798	$ 14,394

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.

(In thousands)	Quarter Ended June 30, 2001	Quarter Ended Sept. 30, 2001	Quarter Ended Dec. 31, 2001	Quarter Ended March 31, 2002
Operating revenue	$145,016	$147,151	$136,065	$132,186
Operating income	$ 22,834	$ 25,062	$ 20,221	$ 18,237
Net income	$ 20,371	$ 22,573	$ 17,852	$ 15,978

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.

~~Per~~Net cash ~~share~~flows ~~data~~used isin ~~not~~investing ~~relevant~~activities ~~because~~for the ~~Company's~~fiscal ~~common~~year ~~stock is~~ended ~~wholly~~March 31, ~~owned~~2005 byand ~~National~~2004 ~~Grid~~were ~~USA~~approximately $79 million and $25 million, arespectively. ~~wholly~~Cash ~~owned~~expenditures ~~subsidiary~~for ofthese ~~National~~periods ~~Grid~~were primarily transmission utility ~~Transco~~plant ~~plc~~expenditures. The funds necessary for utility plant expenditures during the period were primarily provided by internal funds.

~~ITEM~~Net ~~9. CHANGES~~cash INflows ~~AND~~used ~~DISAGREEMENTS~~in ~~WITH~~financing ~~ACCOUNTANTS~~activities ONfor ~~ACCOUNTING~~the ~~AND~~fiscal year ended March 31, 2005 was ~~FINANCIAL~~approximately ~~DISCLOSUREThe~~$236,000. ~~Company~~Cash ~~has~~expenditures ~~nothing~~for the period were due primarily to ~~report~~dividends ~~for~~paid ~~this~~on ~~item~~preferred stock and preferred stock retirements.

~~PART~~At ~~III~~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.

~~ITEM~~At ~~10. DIRECTORS~~March 31, ~~AND~~2005, ~~EXECUTIVE~~the ~~OFFICERS~~Company OFhad credit and standby bond purchase facilities with banks totaling ~~THE~~$440 million ~~REGISTRANTThe~~which ~~following~~are ~~table~~available ~~lists~~to provide liquidity support for $410 million of the Company’s ~~executive~~long-term ~~officers~~bonds and ~~directors:~~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.

Name	Age	Position
Peter G. Flynn	49	President and Director (until April 16, 2003)
Stephen P. Lewis	46	President and Director (effective April 16, 2003)
John G. Cochrane	45	Chief Financial Officer and Director
Marc F. Mahoney	49	Vice President
Lawrence J. Reilly	47	Vice President and Director
James S. Robinson	50	Treasurer
Masheed H. Rosenqvist	48	Vice President
Herb Schrayshuen	49	Vice President
Edward A. Capomacchio	57	Controller
Michael E. Jesanis	46	Director
Nick Winser	42	Director

~~Section~~Contractual ~~16(a)~~Obligations: ~~Beneficial~~The ~~Ownership~~Company’s ~~Reporting~~capital obligations consist of amounts for purchased power, long-term debt maturities, construction expenditures and operating leases. ~~Compliance~~Payments by fiscal year are as follows:

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


	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

ITEM 11. EXECUTIVE COMPENSATION

*	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.

~~Summary~~Expected ~~Compensation~~contributions ~~TableThe~~to ~~following table sets forth~~ the ~~compensation~~ ~~paid~~Company’s orpension ~~accrued~~and ~~for~~post-retirement ~~services~~benefit ~~rendered~~plans totrusts ~~NEP~~(as disclosed in ~~fiscal~~Item 8. ~~years~~Financial ~~2003, 2002~~Statements and ~~2001~~Supplementary byData - ~~the~~Note ~~president~~H. ~~and~~“Employee ~~the~~Benefits”) ~~two most highly paid persons who were~~are ~~serving~~not asincluded ~~executive officers~~ on ~~March 31, 2003 (~~the ~~Named~~above ~~Executive Officers)~~table.

Name and Principal Position (a)	Year	Annual Compensation (b)			Long-Term Compensation AwardsSecurities Underlying Options (#)	All Other Compen-sation($)(e)
		Salary($)	Bonus($)(c)	Other Annual Compen-sation($)(d)
Peter G. FlynnPresident	200320022001	64,654180,630177,211	35,756109,35330,270	5,88719,31312,175	7,26716,8250	200452432
Marc F. MahoneyVice President	200320022001	74,778106,485118,010	39,66464,67578,428	9,44312,63711,352	8,4089,70235,886	122165280
Masheed H. RosenqvistVice President	200320022001	158,280152,196146,112	70,90070,47917,892	19,17918,15418,452	17,78914,7110	484464539

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.

~~(a)~~Cost ~~Certain officers~~ of ~~NEP~~Removal: ~~are~~The ~~also~~Company ~~officers~~estimates ofit ~~affiliate~~has ~~companies.~~collected ~~Beginning~~over ~~with~~time ~~fiscal~~approximately ~~year~~$20 million ~~2003 compensation that is allocable to NEP is set forth in the table. (b) Includes deferred compensation in category~~ and ~~year~~$19 million ~~earned.~~for ~~(c)~~cost ~~The bonus figure represents cash bonuses and the fair market value~~ of ~~unrestricted~~removal ~~securities~~through ofMarch 31, ~~National~~2005 ~~Grid Transco awarded under an incentive compensation plan~~ and ~~cash~~2004, ~~bonuses awarded under the all-employees goals program~~respectively. ~~(d)~~For ~~Includes~~more ~~amounts~~information about ~~reimbursed for~~ the ~~payment~~cost of ~~taxes~~removal onsee ~~certain~~Note ~~noncash~~L ~~benefits~~“Cost ~~and~~of ~~contributions~~Removal” toin ~~the incentive thrift plan that are not bonus contributions, including related deferred compensation plan match~~Item 8. ~~(e)~~Financial ~~Includes~~Statements ~~Company~~and Supplementary ~~contributions to life insurance~~Data.

~~Option~~New ~~Grants~~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 ~~Last~~2006. ~~Fiscal~~The ~~YearThe~~Act provides ~~following~~employers ~~table~~currently sponsoring prescription drug programs for Medicare-eligibles with a ~~shows~~range ~~all~~of ~~stock~~options ~~option~~for ~~grants~~coordinating with the new government-sponsored program to potentially reduce program costs. These options include supplementing the ~~Named~~government ~~Executive~~program ~~Officers~~on ~~during~~a ~~fiscal~~secondary ~~year~~payor ~~2003~~basis or accepting a direct subsidy from the government to support a portion of the cost of the employer’s program.

Individual Grants					Potential Realizable Value at Assumed Annual Rates of Stock Price Appreciation for Option Term
Name	Number of Option Shares Granted (a)	% of Total Option Shares Granted to Employees in Fiscal Year (b)	Exercise Price ($/Sh) (c)	Expiration Date	5% ($)	10% ($)
Peter G. Flynn	21,569	1.0%	7.117	June 2012	96,539	244,650
Marc F. Mahoney	18,407	.9%	7.117	June 2012	82,387	208,784
Masheed H. Rosenqvist	17,789	.8%	7.117	June 2012	79,620	201,775

~~The~~Paragraph 40 ~~options~~of ~~vest~~the ~~over~~Financial ~~time,~~Accounting ~~subject~~Standards toBoard’s a(FASB) Statement ~~performance~~of ~~condition. The~~Financial Accounting ~~options~~Standard ~~are~~(SFAS) No. 106, ~~exercisable~~“Employers’ ~~only~~Accounting iffor ~~and~~Postretirement toBenefits ~~the~~Other ~~extent~~Than Pensions” requires that ~~National~~presently ~~Grid’s~~enacted changes in laws impacting employer-sponsored retiree health care ~~total~~programs ~~shareholder~~which ~~return~~take ~~(as~~effect ~~defined~~in future periods be considered in ~~the~~current-period ~~applicable~~measurements ~~plan)~~for benefits ~~during~~expected ~~the~~to ~~three~~be provided in those future periods. Therefore, under FAS 106 guidance, ~~years~~measures of ~~the~~plan ~~performance~~liabilities ~~period~~and isannual ~~equal~~expense toon or ~~better~~after ~~than~~ the ~~median~~date of aenactment should reflect ~~specific~~the ~~comparison~~effects ~~group~~of this Act. If ~~the~~Pursuant ~~performance~~to ~~condition~~guidance isfrom ~~not~~the ~~met~~FASB ~~after~~under FSP FAS 106-2, the retiree health ~~three-year~~obligations ~~period,~~will reflect the ~~National~~estimated ~~Grid~~subsidy ~~Transco~~payments ~~Remuneration~~expected ~~Committee~~from ~~may~~the ~~modify~~federal government for the ~~performance~~participant ~~condition~~groups oranticipated ~~methodology~~to onqualify ~~subsequent~~for ~~anniversaries~~the ofsubsidy. ~~the~~Participant groups who are not ~~performance~~expected ~~period~~to qualify, ~~taking~~or ~~into~~have ~~account~~not ~~any~~yet ~~factor~~been itdetermined ~~deems~~whether ~~relevant.~~they will qualify, for the federal ~~Option~~subsidy ~~Exercises~~will innot ~~Fiscal~~impact ~~Year~~the ~~2003~~retiree ~~and~~health ~~Fiscal~~obligations. ~~Year-End~~If ~~Option ValuesThe~~any ~~following~~portion ~~table~~of ~~sets~~this ~~forth,~~group is subsequently determined to qualify for the ~~Named~~subsidy, ~~Executive~~the retiree health care obligations will be ~~Officers,~~adjusted at the ~~number~~time of ~~shares~~that ~~for~~determination. ~~which~~The ~~stock~~Company ~~options~~has ~~were~~chosen ~~exercised~~to inapply ~~fiscal year~~the ~~2003~~guidance prospectively, ~~the~~impacting ~~realized~~retiree ~~value~~health orcosts. ~~spread~~The (Company adopted the ~~difference~~provisions ~~between~~of ~~the~~FAS ~~exercise~~106-2 on ~~price~~July 1, ~~and~~2004. ~~market~~Reduced ~~value~~expense onresulting from the ~~date~~Act of ~~exercise)~~approximately ~~and~~$1 million ~~the~~was ~~number~~credited ~~and unrealized~~to ~~spread~~customers. ofSee ~~the~~Note ~~unexercised~~H ~~options~~“Employee ~~held~~Benefits” byin ~~each~~Item 8. atFinancial ~~fiscal year-end~~Statements and Supplementary Data.

Name	Options Exercised (#)	Value Realized ($)	Number of Shares Underlying Unexercised Options on March 31, 2003 (a)		Value of Unexercised Options on March 31, 2003 (b)
			Vested	Unvested	Vested	Unvested
Peter G. Flynn	0	0	0	26,192	0	0
Marc F. Mahoney	0	0	0	31,228	0	0
Masheed H. Rosenqvist	0	0	0	48,523	0	0

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.

(a)	The first of the options were to have vested in March 2003 but did not, as the Company did not meet specified performance conditions.
(b)	At March 31, 2003, the price per ordinary share on the London Stock Exchange was lower than the exercise price for any of the Named Executive Officers’ stock options.

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.

~~Pension~~This ~~PlansThe~~statement ~~Named~~will ~~Executive~~be ~~Officers~~effective ~~participate~~for in the ~~National~~fiscal ~~Grid~~year ~~USA~~ended ~~Companies Final Average Pay Pension Plan (FAPP). FAPP is a noncontributory~~March 31, ~~tax-qualified~~2006 ~~defined~~for ~~benefit plan which provides all employees of National Grid USA and its subsidiaries with a minimum retirement benefit. Pension benefits are related to compensation, subject to~~ the ~~maximum annual limits noted in the pension table below~~Company. ~~Under~~ ~~FAPP, a~~The ~~participant’s~~adoption ~~retirement benefit is computed using formulas based on percentages~~ of ~~highest~~FIN ~~average~~47 compensation computed over five consecutive years. The compensation covered by the pension plan includes salary, bonus and incentive share awards.The Executive Supplemental Retirement Plan (“ESRP”) is anot ~~noncontributory,~~expected ~~nonqualified defined benefit plan that provides additional retirement benefits~~ to ~~the~~have ~~Named Executive Officers and certain members of management who are eligible to receive~~ a ~~FAPP~~material ~~benefit~~impact ~~and whose compensation exceeds legal limits under the applicable plan or who are otherwise selected for participation. Depending~~ on the ~~participant,~~Company’s ~~the~~results ~~ESRP may provide for unreduced benefits payable as early as age 55, may enhance the qualified plan formula, may give credit for more years~~ of ~~service~~ operations or ~~may~~its ~~award benefits~~financial ~~not otherwise payable due to limits on benefits that can be provided under the qualified plan~~position.

~~Pension~~ITEM ~~Plan~~7A. ~~Table~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

~~The~~Interest ~~following~~Rate ~~table~~Risk: ~~shows~~The ~~the~~Company’s ~~maximum~~major ~~retirement~~financial ~~benefit~~market ~~(adjusted~~risk ~~for Social~~exposure ~~Security,~~is ifchanging ~~applicable)~~interest anrates. Changing ~~executive~~interest ~~officer~~rates ~~can~~will ~~earn~~affect ininterest ~~aggregate~~paid ~~under FAPP~~on ~~together~~variable ~~with~~rate ~~the ESRP~~debt. ~~The~~ ~~benefit~~At ~~calculations are made as of~~ March 31, ~~2003~~ 2005 and 2004, ~~assume~~respectively, the ~~officer~~Company’s ~~has~~tax ~~selected~~exempt avariable ~~straight~~rate ~~life~~long-term ~~annuity~~debt ~~commencing~~had ata carrying value of ~~age~~approximately 65$410 million. ~~Annual~~ ~~compensation~~While ~~limits~~the ofultimate ~~$200,000~~maturity ~~under~~dates aof ~~tax-qualified~~the ~~plan~~underlying ~~will~~loan agreements ~~reduce~~range ~~the~~from ~~portion~~2015 ~~payable~~through ~~for~~2022, ~~some~~this ~~highly~~debt ~~compensated~~is ~~officers~~issued in tax exempt commercial paper mode. The ~~benefits~~various ~~listed~~components ~~are~~that ~~shown~~comprise ~~without~~this ~~any~~debt ~~joint~~are ~~and~~issued ~~survivor~~for ~~benefits. If~~periods atranging ~~age~~from 65one ~~a participant~~day ~~elected~~to a270 days, ~~100~~and ~~percent~~are remarketed ~~joint~~through ~~and~~remarketing ~~survivor~~agents ~~benefit~~at ~~with~~the aconclusion ~~spouse~~ of ~~the~~ ~~same~~each ~~age,~~period. ~~the~~The ~~benefit~~weighted ~~shown~~average variable ininterest rate for the ~~table~~fiscal ~~would~~year beended ~~reduced~~March 31, by2005 was approximately 16 1.58 percent.

Five-Year Average Compensation	Years of Service
	10	15	20	25	30	35
$100,000	$18,922	$27,383	$35,844	$44,056	$52,267	$57,228
$150,000	$29,922	$43,383	$56,844	$69,931	$83,017	$91,228
$200,000	$40,922	$59,383	$77,844	$95,806	$113,767	$125,228
$250,000	$51,922	$75,383	$98,844	$121,681	$144,517	$159,228
$300,000	$62,922	$91,383	$119,844	$147,556	$175,267	$193,228
$350,000	$73,922	$107,383	$140,844	$173,431	$206,017	$227,228
$400,000	$84,922	$123,383	$161,844	$199,306	$236,767	$261,228
$450,000	$95,922	$139,383	$182,844	$225,181	$267,517	$295,228
$500,000	$106,922	$155,383	$203,844	$251,056	$298,267	$329,228

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.

~~For purposes of the pension program, the Named~~15 Executive Officers had approximately the following credited years of benefit service at March 31, 2003: Mr. Flynn, 21 years; Ms. Rosenquivst, 21 years; and Mr. Mahoney, 26 years. At retirement, the Named Executive Officers may become eligible for post-retirement health and life insurance benefits determined based on their age and service. The executive may be required to contribute to the cost of benefits, depending on date of hire and total years of service.

ITEM 128. ~~SECURITY~~ ~~OWNERSHIP~~FINANCIAL OFSTATEMENTS ~~CERTAIN~~AND ~~BENEFICIAL~~SUPPLEMENTARY ~~OWNERS AND MANAGEMENT~~DATA

The following table indicates the number of ordinary shares of National Grid Transco beneficially owned as of June 19, 2003 by: (a) each director of the Company; (b) each of the Named Executive Officers; and (c) all directors and executive officers of the Company as a groupA. ~~Except~~ asFINANCIAL ~~indicated, each such~~STATEMENTS ~~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*
Peter G. Flynn	29,040
Stephen P. Lewis	1,671
John G. Cochrane	24,860
Marc F. Mahoney	16,710
Lawrence J. Reilly (a)	27,740
Masheed H. Rosenqvist	9,795
Michael E. Jesanis	34,925
Nick Winser	17,489
All directors and officers as a group (10 persons)(a)(b)	145,255

	•		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

* 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. (b) Does not include securities held by Mr. Flynn, as he is not currently a director or officer of the Company.16

~~None.~~Report of Independent Registered Public Accounting Firm

~~PART~~To IVthe Stockholders and Board of Directors of New England Power Company:

~~ITEM~~In ~~14. CONTROLS~~our ~~AND~~opinion, ~~PROCEDURESThe~~the ~~Company~~accompanying ~~has established~~balance sheets and ~~maintains~~the ~~disclosure~~related ~~controls~~statements ~~and~~of ~~procedures~~income, ~~which are designed~~of tocomprehensive ~~provide~~income, ~~reasonable~~of ~~assurance~~retained ~~that~~earnings ~~material~~and ~~information~~of ~~relating~~cash toflows ~~the Company~~present fairly, ~~including~~in ~~its~~all ~~consolidated subsidiaries~~material respects, isthe ~~made~~financial ~~known~~position toof ~~management~~New ~~by others~~England ~~within~~Power ~~those~~Company ~~entities~~at March 31, ~~particularly~~2005 ~~during~~and ~~the~~2004, ~~period~~and ~~in which this~~the ~~quarterly~~results ~~report~~of isits ~~being~~operations ~~prepared. The~~and ~~Company~~its ~~has~~cash ~~established~~flows afor ~~Disclosure Committee,~~each ~~which~~of isthe ~~made~~three upyears ofin ~~several~~the ~~key~~period ~~management~~ended ~~employees and which~~March ~~reports~~31, ~~directly~~2005 toin ~~the~~conformity ~~Chief~~with ~~Financial~~accounting ~~Officer~~principles ~~and~~generally ~~President. The~~accepted ~~Disclosure Committee~~in ~~monitors~~the ~~and~~United ~~evaluates~~States ~~these disclosure controls and procedures. The~~of ~~Chief~~America. ~~Financial~~These ~~Officer~~financial ~~and~~statements ~~President~~are ~~have evaluated~~ the ~~effectiveness~~responsibility of the Company’s ~~disclosure~~management. ~~controls~~Our responsibility ~~and~~is ~~procedures~~to asexpress ofan aopinion ~~date~~on ~~within~~these 90financial ~~days prior~~statements tobased ~~the~~on ~~filing~~our ~~date~~audits. ofWe conducted ~~this~~our ~~annual~~audits ~~report. Based~~of onthese ~~this~~statements ~~evaluation,~~in ~~it was~~accordance ~~determined~~with ~~that~~the ~~these~~standards ~~disclosure~~of ~~controls~~the ~~and~~Public ~~procedures~~Company Accounting ~~were~~Oversight ~~effective~~Board ~~in providing~~(United ~~reasonable~~States). ~~assurance~~Those ~~during~~standards ~~the~~require ~~period~~that ~~covered~~we inplan ~~this~~and ~~annual~~perform ~~report.~~the ~~There~~audit ~~were~~to noobtain ~~significant~~reasonable ~~changes~~assurance inabout ~~internal~~whether ~~controls~~the orfinancial instatements ~~other~~are ~~factors~~free ~~that~~of material ~~could~~misstatement. ~~significantly~~An ~~affect~~audit ~~internal~~includes ~~controls~~examining, ~~subsequent~~on toa ~~the~~test ~~date~~basis, ofevidence supporting the ~~most~~amounts and ~~recent~~disclosures ~~evaluation.ITEM~~in ~~15.~~the ~~EXHIBITS~~financial ~~AND~~statements, ~~REPORTS~~assessing ONthe ~~FORM 8-KReports~~accounting onprinciples ~~Form~~used ~~8-KThe~~and ~~Company did not file any~~significant ~~current~~estimates ~~reports~~made onby ~~Form~~management, ~~8-K~~and ~~during~~evaluating the ~~last~~overall ~~quarter~~financial ofstatement ~~fiscal~~presentation. ~~year~~We believe ~~ended~~that ~~March 31,~~our ~~2003.ExhibitsThe~~audits ~~exhibit~~provide ~~index~~a isreasonable ~~incorporated~~basis ~~herein by~~for ~~reference~~our opinion.

~~SIGNATURES~~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.

~~Pursuant~~/s/ toPricewaterhouseCoopers ~~the Requirements of Section 13 or 15(d) of the Securities~~LLP ~~Exchange~~PricewaterhouseCoopers ~~Act of 1934, the registrant has duly caused this report to be signed on~~LLP ~~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~~Boston, ~~ENGLAND~~Massachusetts May 18, ~~POWER~~2005, except ~~COMPANY~~for ~~By:~~the ~~/s/~~USGen ~~Stephen~~New PEngland, Inc. ~~Lewis~~settlement ~~Stephen~~section of P.Note ~~Lewis~~B ~~President~~as to which the date is June 9, 2005 and for Note N as to which the date is July 6, 2005.

~~Pursuant to the requirements of the Securities Exchange Act of 1934,~~17 this report has been signed below on June 27, 2003 by the following persons on behalf of the registrant and in the capacities indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company.

Registrant

Shares Outstanding at July 12, 2005

New England Power Company

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

~~CERTIFICATIONS~~New England Power Company Statements of Income

Certification of Principal Executive OfficerI, Stephen P. Lewis, certify that:1. I have reviewed this annual report on Form 10-K of New England Power Company (the “Report”);2. Based on my knowledge, this Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Report; 3. Based on my knowledge, the financial statements, and other financial information included in this Report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report is being prepared;b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this Report (the “Evaluation Date”); andc) presented in this Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; andb) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and 6. The registrant’s other certifying officers and I have indicated in this Report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


	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

Date: June 27, 2003	/s/ Stephen P. Lewis
	Stephen P. Lewis
	President

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

~~Certification of Principal Financial OfficerI, John~~18 G. Cochrane, certify that:1. I have reviewed this annual report on Form 10-K of New England Power Company (the “Report”);2. Based on my knowledge, this Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Report; 3. Based on my knowledge, the financial statements, and other financial information included in this Report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report is being prepared;b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this Report (the “Evaluation Date”); andc) presented in this Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; andb) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and 6. The registrant’s other certifying officers and I have indicated in this Report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: June 27, 2003	/s/ John G. Cochrane
	John G. Cochrane
	Vice President and Chief Financial Officer

~~EXHIBIT~~New ~~INDEX~~England Power Company Statements of Comprehensive Income

Exhibit No.

Description

Year Ended March 31,

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)

(In thousands)

2005

2004

2003

3.2

By-laws of the Company as amended February 20, 2003

(Restated) (See Note N)

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)

Net income

76,808

76,443

79,669

10.2*

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

Unrealized gain (loss) on securities, net of tax

)

317

(120

)

10.3*

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

Comprehensive income (Note A)

76,807

76,760

79,549

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)

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)

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)

10.10*

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)

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*

USGen New England Contract: Wholesale Sales Agreement between the Company and USGen New England, Inc. dated as of August 5, 1997 (Exhibit 10(gg)(ii) to 1997 Form 10-K, File No. 1-6564); Amendment No. 1 dated as of September 25, 1997, Amendment No. 2 dated as of September 1, 1998 (Exhibit 10(ee)(ii) to 1999 Form 10-K, File No. 1-6564); Amendment No. 3 dated as of December 23, 1999 (Exhibit 10(aa) (ii) to 2001 Form 10-K, File No. 1-6564); Amendment No. 4 dated as of November 20, 2001 (Exhibit 10(aa)(ii) to 2002 Form 10-K, File No. 1-6564)

10.15

Amendment No. 5 dated as of July 31, 2002 to Wholesale Sales Agreement between the Company and USGen New England, Inc.; Amendment No. 6 dated as of July 31, 2002 to Wholesale Sales Agreement between the Company and USGen New England, Inc.

10.16*

Amended and Restated PPA Transfer Agreement between the Company and USGen New England, Inc. dated as of October 29, 1997 (Exhibit 10(aa) (iii) to 2001 Form 10-K, File No. 1-6564); First Amendment to Amended and Restated PPA Transfer Agreement dated as of October 10, 2001 (Exhibit 10(aa)(iii) to 2002 Form 10-K, File No. 1-6564)

10.17*

Form of PSA Performance Support Agreement between the Company, USGen New England, Inc., and each of the following; Unitil Power Corp. (Ocean State), Braintree Electric Light Department, Littleton Electric Light Department, Massachusetts Government Land Bank, Shrewsbury Electric Light Plant, and Taunton Municipal Light Plant, dated as of August 5, 1997 (Exhibit 10(gg)(iv) to 1997 Form 10-K, File No. 1-6564)

10.18*

Quebec Interconnection Transfer Agreement between the Company, The Narragansett Electric Company, and USGen New England, Inc. dated as of September 1, 1998 (Exhibit 10(ee)(v) to 1999 Form 10-K, File No. 1- 6564)

99.1

Certification of Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

99.2

Certification of Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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

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 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

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.

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)

Filing Compare · NEW ENGLAND POWER CO