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

FORMWashington, 10-KD.C. 20549

[X] ANNUALFORM REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 10-K

~~For~~X ~~the~~ANNUAL ~~fiscal~~REPORT ~~year~~PURSUANT ~~ended~~TO ~~December~~SECTION ~~31,~~13 ~~2001~~OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended OR March 31, 2003

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

~~For~~TRANSITION ~~the~~REPORT ~~transition~~PURSUANT ~~period~~TO ~~from~~SECTION ~~__________~~13 toOR ~~__________~~ 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

~~1-2987 Niagara~~For ~~Mohawk~~the ~~Power Corporation~~transition 15-0265555 (a New York corporation) 300 Erie Boulevard West Syracuse, New York 13202 315.474.1511 period___________to______________

Securities registered pursuant to Section 12(b) of the Act: (Each class is registered on the New York Stock Exchange)

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

1-2987	Niagara Mohawk Power Corporation	15-0265555
	(a New York corporation) 300 Erie Boulevard West Syracuse, New York 13202 315.474.1511

~~Registrant Title~~Securities ~~and Class~~ registered ~~Niagara~~pursuant ~~Mohawk~~to ~~Power~~Section ~~Corporation Preferred Stock~~ 12(~~$100 par value-cumulative~~b)~~: 3.40%~~ ~~Series 3.90%~~of ~~Series 4.85% Series~~the ~~3.60%~~Act:(Each ~~Series 4.10%~~class ~~Series 5.25%~~is ~~Series Preferred~~registered ~~Stock~~on ~~($25 par value-cumulative):~~the ~~Adjustable~~New ~~Rate~~York ~~Series~~Stock ~~A, C & D~~ Exchange)

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

Registrant	Title and Class

Niagara Mohawk Power Corporation	Preferred Stock ($100 par value-cumulative):

~~Indicate~~3.90% bySeries 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 regsitrant'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-K3. [60% ~~X ]~~ Series

~~State~~Preferred ~~the~~Stock ~~aggregate~~($25 ~~market~~par value ~~of the voting stock held by non~~-~~affiliates~~cumulative): ofAdjustable ~~the~~Rate ~~registrant.~~ Series D

Securities registered ~~Registrant Market~~pursuant ~~Value~~to atSection ~~March~~12(g) ~~22,~~of ~~2002~~ the Act: None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and ~~Niagara~~(2) ~~Mohawk~~has ~~Power~~been ~~Corporation~~ subject to such filing requirements for the past 90 days. YES [ X ] ~~None~~ NO [ ]

Indicate ~~the~~by ~~number~~check ofmark ~~shares~~if ~~outstanding~~disclosure of delinquent ~~each~~filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’'s ~~classes~~knowledge, in definitive proxy or information statements incorporated by reference in Part III of ~~common~~this ~~stock,~~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). YES [ ] NO [ X ]State the aggregate market value of the ~~latest~~common ~~practicable~~equity ~~date.~~held by non-affiliates of the registrant: N/A

~~Registrant~~ Indicate the number of shares outstanding of ~~Title Shares~~each ~~Outstanding~~of atthe ~~March~~registrant’s 22classes of common stock, ~~2002~~as of the latest practicable date.

Niagara Mohawk Power Corporation Common Stock, $1.00 par value 187,364,863 (all held by National Grid)

Registrant	Title	Shares Outstanding at June 24, 2003

Niagara Mohawk Power Corporation	Common Stock, $1.00 par value	187,364,863
	(all held by Niagara Mohawk Holdings, Inc.)

NIAGARA MOHAWK POWER CORPORATION ~~INFORMATION REQUIRED IN FORM 10-K INDEX~~

~~PART~~TABLE I OF CONTENTS

		Glossary of Terms
PART I
Item 1.	~~Item 1.~~Business	~~Business~~
Item 2.	~~Item 2.~~Properties	~~Properties~~
Item 3.	~~Item~~Legal 3.Proceedings	~~Legal Proceedings~~
Item 4.	~~Item~~Submission 4.of Matters to a Vote of Security Holders	~~Submission of Matters to a Vote of Security Holders~~
		Executive Officers of the Registrant
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
Item 14.	Controls and Procedures
PART IV
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K
Signatures
Certifications

~~PART~~FORWARD-LOOKING II INFORMATION

	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

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

(a) the impact of further electric and gas industry restructuring;

(b) the impact of general economic changes in New York;(c) federal and state regulatory developments and changes in law which may have a ~~PART~~substantial ~~III~~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) climatic changes or unexpected changes in weather patterns; and(i) failure to recover costs currently deferred under the provisions Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulations”, as amended, and the Merger Rate Plan in effect with the New York State Public Service Commission.

	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

NIAGARA MOHAWK POWER CORPORATION

PART IV I

~~Item~~ITEM 141. BUSINESSOn ~~Exhibits~~January 31, 2002, Niagara Mohawk Holdings, Inc. (“Holdings”), parent company of Niagara Mohawk Power Corporation (the “Company”) became a wholly owned subsidiary of National Grid USA (“National Grid”). National Grid is a wholly owned subsidiary of National Grid Transco plc (“NGT”). NGT owns and operates the high voltage transmission system and natural gas distribution system in England and Wales. NGT, through National Grid, also has substantial transmission and distribution operations in the United States. The combination of the Company and National Grid more than doubled the size of NGT’s U.S. operations, with an electric customer base of approximately 3.3 million.The Company was organized in 1937 under the laws of New York State and is engaged principally in the regulated energy delivery business in New York State. The Company provides electric service to approximately 1,500,000 electric customers in the areas of eastern, central, northern and western New York and sells, distributes, and transports natural gas to approximately 557,000 gas customers in areas of central, northern and eastern New York State.In conjunction with the closing of the merger with National Grid a new rate plan (“Merger Rate Plan”) that had previously been approved by the PSC went into effect, superceding the Power Choice rate plan. See Part II, Item 7. Management’s Discussion and Analysis of Financial ~~Statement~~Condition ~~Schedules~~and Results of Operations, “Regulatory Agreements and ~~Reports~~the onRestructuring ~~Form~~of ~~8–K~~the ~~Signatures~~Regulated Electric Business - Merger Rate Plan” for a detailed discussion of this rate plan.For a discussion of events that occurred during 2003 and 2002, including the restructuring of the regulated electric utility business, other federal and state regulatory initiatives, and the Company’s efforts to address deregulation and its financial condition, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

~~NIAGARA~~REGULATION ~~MOHAWK~~AND ~~POWER CORPORATION GLOSSARY OF TERMS~~RATES

TERM	DEFINITION
AFC	Allowance for Funds Used During Construction
CTC	Competitive transition charges: a mechanism established in Niagara Mohawk’s Power Choice agreement to recover stranded costs from customers
DOE	U.S. Department of Energy
Dth	Dekatherm: one thousand cubic feet of gas with a heat content of 1,000 British Thermal Units per cubic foot
EBITDA	A non–GAAP measure of cash flow which is calculated as: earnings before interest charges, interest income, income taxes, depreciation and amortization, and other non-cash items, including amortization of nuclear fuel, allowance for funds used during construction, amortization of nuclear regulatory assets, amortization/accretion of MRA/IPP buyout costs, deferral of MRA interest rate savings, and non–recurring and extraordinary items. EBITDA may not be comparable to similarly titled measures used by other companies.
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles
GRT	Gross Receipts Tax
Gwh	Gigawatt–hour: one gigawatt–hour equals one billion watt-hours
IPP	Independent Power Producer: any person that owns or operates, in whole or in part, one or more independent power facilities, including the purchasers of Niagara Mohawk’s generation assets
IPP Party	Independent Power Producers that were a party to the MRA
KWh	Kilowatt–hour: a unit of electrical energy equal to one kilowatt of power supplied or taken from an electric circuit steadily for one hour
Merger Rate Plan	Niagara Mohawk’s ten year rate agreement which became effective on January 31, 2002, the closing of the merger
MRA	Master Restructuring Agreement: a Niagara Mohawk agreement, including amendments thereto, which terminated, restated or amended certain IPP Party power purchase agreements effective June 30, 1998
MRA regulatory asset	Recoverable costs to terminate, restate or amend IPP Party contracts, which have been deferred and are being amortized and recovered under Niagara Mohawk’s Power Choice agreement
MW	Megawatt: one million watts
MWh	Megawatt-hour: one thousand kilowatt-hours
National Grid	National Grid Group plc is an international United Kingdom-based company that builds, owns and manages, electricity and telecommunications networks
Net Cash Interest	Reflects interest charges (net of allowance for funds used during construction) less the non-cash impact of the net amortization of discount on long-term debt and interest accrued on the Nuclear Waste Policy Act disposal liability less interest income
NYISO	New York Independent System Operator
NYPA	New York Power Authority
NYSERDA	New York State Energy Research and Development Authority
Power Choice	Niagara Mohawk's five-year electric rate agreement, which incorporates the MRA agreement, approved by the PSC in an Order dated March 20, 1998, and became effective September 1, 1998
PPA	Power Purchase Agreement: long-term contracts under which a utility is obligated to purchase electricity from an IPP at specified rates
Provider of last resort	The entity that will provide electric or gas commodity to its customers who are unable or unwilling to obtain an alternative supplier
PRP	Potentially Responsible Party (may include current site owner, site owner at the time of disposal, entity who arranged for disposal at the location, or transporters or disposal material)
PSC	New York State Public Service Commission
PURPA	Public Utility Regulatory Policies Act of 1978, as amended. One of five bills signed into law on November 8, 1978, as the National Energy Act. It sets forth procedures and requirements applicable to state utility commissions, electric and natural gas utilities and certain federal regulatory agencies. A major aspect of this law is the mandatory purchase obligation from qualifying facilities.
SEC	Securities and Exchange Commission
SFAS No. 71	Statement of Financial Accounting Standards No. 71 “Accounting for the Effects of Certain Types of Regulation”
SFAS No. 101	Statement of Financial Accounting Standards No. 101 “Regulated Enterprises - Accounting for the Discontinuance of Application of FASB Statement No. 71”
SFAS No. 106	Statement of Financial Accounting Standards No. 106 “Employers’ Accounting for Postretirement Benefits Other Than Pensions”
SFAS No. 109	Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes”
SFAS No. 121	Statement of Financial Accounting Standards No. 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of”
SFAS No. 133	Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities”
Stranded costs	Regulated utility costs that may become unrecoverable due to a change in the regulatory environment
TCC	Transmission Congestion Contract: Transmission congestion is a component of the cost differential in the price of electricity between two geographic locations. A TCC confers on the holder the right to collect or obligation to pay congestion charges for a single megawatt of energy transmitted between those locations.
Unit 1	Nine Mile Point Unit No. 1
Unit 2	Nine Mile Point Unit No. 2

Several critical initiatives have been undertaken by various regulatory bodies and the Company that have had, and are likely to continue to have, a significant impact on the Company and the utility industry. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Regulatory Agreements and the Restructuring of the Regulated Electric Utility Business” and “Other Federal and State Regulatory Initiatives,” for a discussion of these initiatives.

For a discussion of the Merger Rate Plan approved by the PSC in November 2001 and the three-year gas rate settlement agreement, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Regulatory Agreements and the Restructuring of the Regulated Electric Utility Business.”

~~NIAGARA~~ELECTRIC ~~MOHAWK~~SUPPLY ~~POWER CORPORATION~~PLANNING

~~PART~~Although the Company has exited the generation business, the Company must still arrange for electric supply through a transition period and as provider of last resort, in that the Company will provide electricity and gas to its customers who are unable or unwilling to obtain an alternative supplier. Under the Power Choice agreement, the PSC approved the Company’s plan to divest its fossil and hydro generation assets, which was a key component in its Power Choice agreement to lower average electricity prices and provide customer choice. By November 2001, the Company completed the sale of the last of its generation assets, its nuclear assets, to a subsidiary of Constellation Energy Group, Inc. (“Constellation”). In connection with the generation asset sales, the Company has entered into various agreements to purchase its power needs from the buyers of the generation assets or entered into financial swaps with the buyers that hedge the price of electricity. The Company also entered into financial swaps with certain of the parties to the Master Restructuring Agreement (“MRA”). The MRA, which occurred in 1998, terminated, restated, or amended certain Independent Power Producer (“IPP”) Purchase Power Agreements (“PPAs”). The Company continues to purchase energy from various suppliers under long-term PPAs and purchases any additional power needs on the open market through the NYISO. The NYISO commenced operations in December 1999 as a result of a FERC ruling which promotes competition by requiring public utilities owning, operating, or controlling interstate transmission facilities to file tariffs which offer others the same transmission services they provide for themselves, under comparable terms and conditions. For a discussion of the results of the power contracts and several financial agreements to hedge the price of electricity, see Part II, Item 8. Financial Statements and Supplementary Data - Note I. Commitments and Contingencies, and Note J. Derivatives and Hedging Activities.

~~Certain~~ELECTRIC ~~statements~~DELIVERY included in this Annual Report on Form 10-K are forward-looking statements as defined in Section 21E of the Securities Exchange Act of 1934 that involve risk and uncertainty, including Niagara Mohawk’s cash flow, the planned repayment of debt, volatile energy prices and the potential effect it could have on the collection of accounts receivable and the corresponding bad debt expense. These forward-looking statements are based upon a number of assumptions, including assumptions regarding the Power Choice agreement and regulatory actions to continue to support such an agreement and assumptions regarding the Merger Rate Plan. Actual future results and developments may differ materially depending on a number of factors, including regulatory changes either by the federal government or the PSC, including municipalization and exit fees, uncertainties regarding the ultimate impact on Niagara Mohawk as further developments are made in the deregulation of the electric and gas industries, electricity and gas suppliers and other service providers gain open access to Niagara Mohawk’s retail customers, the supply and demand of both gas and electricity, operations at the NYISO including implementation of FERC Order 2000, challenges to the Power Choice agreement under New York laws, the timing and extent of changes in commodity prices and interest rates, the effects of weather, efforts made by Niagara Mohawk to collect from customers, particularly in an environment of rising commodity costs, and the economic conditions of Niagara Mohawk’s service territory. PLANNING

~~ITEM~~As 1of March 31, 2003, the Company had approximately 52,000 pole miles of transmission and distribution lines for electric delivery. Evaluation ~~BUSINESS~~of these facilities relative to NYISO, Northeast Power Coordinating Council, and North American Electric Reliability Organization, planning criteria, security considerations, and anticipated Company internal and external demands is an ongoing process intended to maintain the reliability of electric service while minimizing the capital requirements for expansion of these facilities. The Company continually reviews the adequacy of its electric delivery facilities and establishes capital requirements to support new load growth.

OnGAS March 18, 1999, Niagara Mohawk Power Corporation (“Niagara Mohawk”) was reorganized into a holding company structure in accordance with its Agreement and Plan of Exchange between Niagara Mohawk and Niagara Mohawk Holdings, Inc. (“Holdings”). Niagara Mohawk’s outstanding common stock was exchanged on a share-for-share basis for Holdings common stock. Niagara Mohawk’s preferred stock and debt were not exchanged as part of the share exchange and continue as shares and debt of Niagara Mohawk. To complete the holding company structure, Niagara Mohawk, on March 31, 1999, distributed its ownership in the stock of Opinac North America, Inc. (“Opinac”) as a dividend to Holdings. As a result, Holdings has two subsidiaries, (1) Niagara Mohawk, which is primarily a regulated electric and gas utility, and (2) Opinac, which is mainly involved in unregulated activities in the energy business. SUPPLY

~~Niagara~~The ~~Mohawk~~majority ~~was organized~~of ~~in 1937 under~~ the ~~laws~~Company’s ofgas ~~New~~sales ~~York~~are ~~State~~for residential and commercial isspace ~~engaged~~heating. Consequently, ~~principally in~~ the ~~regulated~~demand ~~energy~~for ~~delivery~~natural ~~business~~gas inby ~~New York State. Niagara Mohawk~~the ~~provides~~Company’s ~~electric~~customers ~~service~~is toseasonal ~~approximately~~and ~~1,500,000~~influenced ~~electric~~by ~~customers~~weather ~~in the~~factors. The ~~areas~~Company ofpurchases ~~eastern,~~its ~~central,~~natural ~~northern~~gas ~~and~~under ~~western~~firm ~~New~~supply ~~York~~agreements. The ~~and~~natural ~~sells, distributes,~~gas ~~and~~purchased ~~transports~~may ~~natural~~be ~~gas~~either totransported ~~approximately~~or ~~540,000~~stored ~~gas~~for ~~customers~~later intransport ~~areas~~on ofa firm ~~central,~~basis ~~northern~~through interstate storage facilities and ~~eastern~~pipelines ~~New~~to ~~York~~the ~~State.~~Company's system.

OnGAS January 31, 2002, Holdings became a wholly owned subsidiary of National Grid. National Grid owns and operates the high voltage transmission system in England and Wales. National Grid, through another subsidiary, National Grid USA, also has substantial transmission and distribution operations in the United States following its acquisitions of New England Electric System and Eastern Utilities Associates in early 2000. The combination of Niagara Mohawk and National Grid more than doubled the size of National Grid’s U.S. operations, with an electric customer base of approximately 3.3 million. DELIVERY

The ~~MRA~~Company ~~and~~sells, ~~the~~distributes ~~Power Choice~~and ~~agreement~~transports ~~that~~natural ~~were~~gas ~~entered~~to ~~into in 1998 provided Niagara Mohawk with~~a ~~financial~~geographic ~~stability~~territory ~~and~~that ~~created~~generally anextends ~~improved~~from ~~platform~~Syracuse ~~upon~~to ~~which it could build value~~Albany. The northern ~~MRA~~reaches ~~and~~of the ~~Power~~system ~~Choice~~extend ~~agreement~~to ~~were~~Watertown ~~the~~and ~~results~~Glens ofFalls. Not ~~negotiations~~all of ~~that~~the ~~Niagara~~Company’s ~~Mohawk~~distribution ~~entered~~areas ~~into~~are tophysically ~~terminate,~~interconnected ~~amend~~with ~~or restate a substantial~~one ~~portion~~another ofby ~~above~~its ~~market~~own ~~PPAs~~facilities. Presently inthere anare ~~effort~~12 toseparate ~~mitigate the escalating cost of~~distribution ~~these~~zones ~~PPAs~~connected asto ~~well~~4 asinterstate tonatural ~~prepare~~gas ~~Niagara~~pipelines ~~Mohawk~~regulated ~~for~~by athe ~~more competitive environment~~FERC. Niagara Mohawk ~~entered~~has ~~into~~nineteen ~~these~~direct ~~state-mandated~~connections ~~PPAs~~with atDominion ~~costs~~Transmission, ~~far exceeding Niagara Mohawk’s avoided costs~~Inc. ~~Avoided costs are the costs~~, ~~Niagara~~two ~~Mohawk~~with ~~would~~Iroquois ~~have~~Gas ~~otherwise~~Transmission, ~~incurred~~one towith ~~generate~~Empire ~~power~~State ifPipeline, itand ~~did~~one ~~not~~with ~~purchase~~Tennessee ~~electricity~~Gas ~~from these sources~~Pipeline.

~~Niagara~~ENVIRONMENTAL Mohawk and the PSC agreed to a five-year rate plan, the Power Choice agreement, and Niagara Mohawk agreed to divest its fossil and hydro generation assets, representing 4,217 MW of capacity and approximately $1.1 billion of net book value. As agreed upon under Power Choice, Niagara Mohawk made available to all customers retail access during 1999. This means that all of Niagara Mohawk’s customers are now able to choose both their electricity and gas supplier. However, Niagara Mohawk will be the provider of last resort for those customers who do not exercise their right to choose a new supplier. With the Power Choice agreement, Niagara Mohawk lowered electric prices beginning on September 1, 1998 for its industrial, commercial and residential electric customers for a period of three years. On August 29, 2001, the PSC approved rate changes to cover the final two years of the Power Choice agreement. The PSC approved the merger rate filing that superseded the Power Choice agreement on January 31, 2002, the closing of the merger with National Grid. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Regulatory Agreements and the Restructuring of the Regulated Electric Business - Merger Rate Plan” for a detailed discussion of this rate plan. MATTERS

General. Niagara Mohawk’s operations and facilities are Assubject ~~part~~to ofnumerous federal, state and local laws and regulations relating to the ~~MRA~~environment including, ~~Niagara Mohawk~~among ~~terminated~~other ~~during~~things, ~~1998~~requirements 18concerning ~~PPAs~~air emissions, ~~for~~water 1discharges,~~092~~ MWsite remediation, ~~restated~~hazardous 8materials ~~PPAs~~handling, waste ~~for~~disposal ~~535~~and MWemployee health and safety. While the Company devotes considerable resources to environmental compliance and ~~amended~~promoting 1employee ~~PPA~~health and ~~for~~safety, 42the MWimpact inof ~~exchange~~future ~~for~~environmental ~~$3.934~~health ~~billion~~and insafety ~~cash~~laws and regulations 20on the Company cannot be predicted with certainty.5In ~~million~~compliance ~~shares~~with ofenvironmental ~~Niagara~~statutes ~~Mohawk~~and ~~common~~consistent ~~stock.~~with its strategic philosophy, the Company performs environmental investigations and analyses and installs, as required, pollution control equipment, including, among other things, effluent monitoring instrumentation and materials storage/handling facilities designed to prevent or minimize releases of potentially harmful substances. The ~~primary~~Company ~~objective~~believes it is probable that costs associated with environmental compliance will continue to be recovered through the ratemaking process. For a discussion of the ~~MRA~~circumstances regarding the ~~was~~Company’s continued ability to ~~convert~~recover athese ~~large~~types of expenditures in rates, see Part II, Item 8. Financial Statements and ~~growing~~Supplementary ~~off~~Data -~~balance~~ ~~sheet~~Note B. ~~payment~~Rate ~~obligation~~and ~~that~~Regulatory Issues and Contingencies.Clean Air Act. ~~threatened~~See ~~the~~Item ~~financial~~3. ~~viability~~Legal Proceedings, for a discussion of ~~Niagara~~the ~~Mohawk~~potential ~~into~~liability for athe ~~fixed~~past operations of Huntley and ~~manageable capital~~Dunkirk ~~obligation~~fossil generating stations.ISO 14001. The ~~lower~~Company’s ~~contractual~~Investment ~~obligations~~Recovery facility ~~resulting~~Environmental ~~from~~Management System (“EMS”) is certified to the International ~~MRA~~Organization for Standardization (“ISO”) 14001 ~~significantly~~standard. The ~~improved~~Company’s ~~cash~~distribution ~~flow~~and ~~which~~transmission isEMS ~~primarily~~are ~~dedicated~~deemed to ~~reduce~~ ~~indebtedness~~be ~~incurred~~in toconformance ~~fund~~with the ~~MRA~~ISO 14001 standard. The ~~With~~NY ~~the~~Transmission ~~improved~~System ~~cash~~EMS has ~~flow~~been ~~and~~integrated ~~proceeds from~~into the ~~generation~~National ~~asset~~Grid ~~sales~~USA Transmission EMS, ~~Niagara~~which ~~Mohawk~~is already ~~reduced~~certified ~~debt~~to byISO ~~approximately~~14001. The NY EMS will be audited for Certification in $1June 2003.9Solid/Hazardous ~~billion~~Waste. The ~~from~~public ~~1999~~utility ~~through~~industry typically ~~2001~~utilizes and/or generates in its operations a broad range of hazardous and potentially hazardous wastes and by-products. The ~~Niagara~~Company ~~Mohawk~~believes it is handling identified wastes and by-products in a manner consistent with federal, state and local requirements and has ~~pursued~~implemented ~~other~~an environmental audit program ~~opportunities~~to identify any potential areas of concern and aid in compliance with such requirements. The Company is also currently conducting a program to ~~reduce~~investigate and ~~its~~remediate, ~~payments~~as necessary to ~~IPPs~~meet ~~that~~current ~~were~~environmental ~~not~~standards, ~~party~~certain properties associated with former gas manufacturing and other properties which the Company has learned may be contaminated with industrial waste, as well as investigating identified industrial waste sites as to which it may be determined that the ~~MRA.~~Company has contributed. The Company has also been advised that ~~Power~~various ~~Choice~~federal, ~~agreement~~state or local agencies believe certain properties require investigation and has prioritized the ~~MRA~~sites ~~facilitated~~based on available information in order to enhance the ~~creation~~management of ainvestigation ~~competitive~~and remediation, if necessary. ~~electricity~~See ~~supply~~Part ~~market~~II, inItem ~~Niagara~~8. ~~Mohawk’s~~Financial ~~service~~Statements ~~territory~~and Supplementary Data - Note I. Commitments and Contingencies, “Environmental Contingencies,” for a discussion of the sites which are Company-owned.

~~For~~EMPLOYEE a discussion of additional events that occurred during 2001 and 2002, including the restructuring of the regulated electric utility business, other federal and state regulatory initiatives, and Niagara Mohawk’s efforts to address deregulation and its financial condition, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. RELATIONS

The ~~following~~Company’s ~~topics~~work ~~are~~force ~~discussed~~at ~~under~~March ~~the~~31, ~~general~~2003 ~~heading~~numbered approximately 5,500, of ~~“Business~~whom approximately 82 percent were union members.” ~~Where~~It ~~applicable,~~is estimated that approximately 80 percent of the ~~discussions~~Company’s ~~make~~total ~~reference~~labor tocost is ~~the~~applicable ~~various~~to ~~other~~operation ~~items~~and ofmaintenance ~~this~~and ~~Form~~approximately ~~10-K.~~20 percent is applicable to construction and other accounts.

~~TOPIC~~SEASONALITY

There is seasonal variation in electric customer load, usually peaking ~~Regulation~~in the winter and ~~Rates Electric~~summer ~~Supply~~months. The ~~Planning~~seasonality is correlated to the colder or ~~Fuel~~warmer temperature in that more electricity is used for ~~Electric~~heating ~~Generation~~or cooling ~~Electric~~during ~~Delivery~~those ~~Planning Gas~~months. There ~~Supply Gas~~is ~~Delivery~~a seasonal variation in gas customer ~~Environmental~~sales, ~~Matters~~with loads usually peaking in the winter months. The seasonality is ~~Research~~correlated ~~and~~to ~~Development~~the colder temperatures in that more gas is used for heating ~~Construction~~during ~~Program~~those months. Also see Part II, Item 8. Financial Statements and ~~Insurance Employee~~Supplementary ~~Relations~~Data - Note P. Quarterly Financial Data ~~Seasonality~~ (unaudited).ITEM 2. PROPERTIES

InELECTRIC ~~addition,~~DELIVERY for a discussion of Niagara Mohawk’s properties, see Item 2. Properties, “Electric Delivery and Gas Delivery.” For a discussion of Niagara Mohawk’s treatment of working capital items, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Financial Position, Liquidity and Capital Resources.” PROPERTIES

~~REGULATION~~As ~~AND~~of ~~RATES~~March 31, 2003, the Company’s electric delivery transmission and distribution systems were composed of:

~~Several~~748 ~~critical initiatives~~substations ~~have~~with ~~been undertaken by various regulatory bodies and Niagara Mohawk that have had, and are likely to continue to have,~~ a ~~significant~~rated ~~impact~~transformer ~~on Niagara~~capacity ~~Mohawk and the utility industry. See Part II, Item 7. Management’s Discussion and Analysis~~ of ~~Financial Condition and Results of Operations,~~approximately ~~“Regulatory Agreements and the Restructuring of the Regulated Electric Utility Business” and “Other Federal and State Regulatory Initiatives~~22,”800,000 ~~for a discussion of these initiatives.~~ kilo-volt-amperes
~~Merger~~approximately ~~Rate Plan. For a discussion of the Merger Rate Plan approved by the PSC in November 2001~~9, ~~see~~400 ~~Part~~pole ~~II,~~miles ~~Item 7. Management’s Discussion and Analysis~~ of ~~Financial Condition~~overhead and ~~Results~~underground ~~of Operations, “Regulatory Agreements and the~~transmission ~~Restructuring of the Regulated Electric Utility Business.”~~ lines
~~Power~~approximately ~~Choice Agreement. For a discussion of Niagara Mohawk’s Power Choice agreement and the MRA~~35,800 ~~see~~conductor ~~Part~~miles ~~II, Item 7. Management’s Discussion and Analysis~~ of ~~Financial~~ ~~Condition~~overhead ~~and~~distribution ~~Results of Operations, “Regulatory Agreements and the Restructuring of the Regulated Electric Utility Business.”~~ lines
~~Multi-year~~about ~~Gas Rate and Restructuring Agreement. For a discussion of Niagara Mohawk’s 2000 three-year gas rate settlement agreement~~5,800 ~~see~~cable ~~Part~~miles ~~II, Item 7. Management’s Discussion and Analysis~~ of ~~Financial~~underground ~~Condition and Results of Operations,~~distribution ~~“Other Federal and State Regulatory Initiatives - Gas Multi-Year Rate and Restructuring Agreement.”~~ cables

~~ELECTRIC~~Only ~~SUPPLY~~a ~~PLANNING~~part of the Company’s transmission and distribution lines are located on property owned by the Company. With respect to the Company’s transmission and distribution lines that are located on property not owned by the Company, the Company’s practice is to obtain right of way agreements.The electric system of the Company is directly interconnected with other electric utility systems in New York, Massachusetts, Vermont, Pennsylvania, and the Canadian provinces of Ontario and Quebec, and indirectly interconnected with most of the electric utility systems through the Eastern Interconnection of the United States and Canada.

~~Although~~GAS Niagara Mohawk has exited the generation business, Niagara Mohawk must still arrange for electric supply through a transition period and as provider of last resort. Under the Power Choice agreement, the PSC approved Niagara Mohawk’s plan to divest its fossil and hydro generation assets, which is a key component in its Power Choice agreement to lower average electricity prices and provide customer choice. During 1999, Niagara Mohawk completed the sale of its coal-fired generation assets, its hydro generation assets, and its oil and gas-fired plant at Oswego. During 2000, Niagara Mohawk completed the sale of its oil and gas-fired plant at Albany and during 2001, Niagara Mohawk completed the sale of its interest in the Roseton oil and gas-fired generation plant and its nuclear assets to a subsidiary of Constellation Energy Group, Inc. (“Constellation”). In connection with these generation asset sales, Niagara Mohawk has entered into various agreements to purchase its power needs from the buyers of the generation assets or entered into financial swaps with the buyers that hedge the price of electricity. Niagara Mohawk also entered into financial swaps with certain of the parties to the MRA. Niagara Mohawk continues to purchase energy from various suppliers under long-term PPAs and purchases any additional power needs on the open market through the NYISO. The NYISO commenced operations in December 1999 as a result of a FERC ruling which promotes competition by requiring public utilities owning, operating, or controlling interstate transmission facilities to file tariffs which offer others the same transmission services they provide for themselves, under comparable terms and conditions. One result of the formation of the NYISO was the dissolution of the New York Power Pool. For a discussion of the results of the generation asset sales to date, a discussion of the formation of the NYISO, a discussion of power contracts and several financial agreements to hedge the price of electricity, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Regulatory Agreements and the Restructuring of the Regulated Electric Utility Business,” “Generation Asset Sales,” and “FERC Order 888 - Open Access,” and Item 8. Financial Statements and Supplementary Data - Note 8. Commitments and Contingencies, and Note 9. Fair Value of Financial and Derivative Financial Instruments. DELIVERY

~~FUEL~~The ~~FOR~~Company ~~ELECTRIC~~distributes ~~GENERATION~~gas that it purchases from suppliers, and transports gas owned by others. As of March 31, 2003, the Company’s natural gas delivery system was comprised of approximately 8,400 miles of pipelines. Only a part of these natural gas pipelines and mains are located on property owned by the Company. With respect to natural gas pipelines and mains that are not located on property owned by the Company, the Company’s practice is to obtain right of way agreements.

Coal, Oil, Gas and Nuclear. As a result of the sales of its nuclear and fossil-fired generation assets, Niagara Mohawk no longer is required to arrange for coal, oil, gas and nuclear fuel supplies. SUBSIDIARIES

~~ELECTRIC~~The ~~DELIVERY~~Company ~~PLANNING~~has the following 100 percent owned subsidiaries:

~~See~~NM ~~Part II~~Uranium, ~~Item 7~~Inc. ~~Management’s~~ ~~Discussion~~- ~~and~~has ~~Analysis~~an ofinterest ~~Financial~~in ~~Condition~~a ~~and~~uranium ~~Results~~mining ~~of Operations,~~operation ~~“Regulatory~~in ~~Agreements~~Live ~~and the Restructuring of the Regulated~~Oak ~~Electric Utility Business” and “FERC Order 888 - Open Access~~County,” ~~as to~~Texas. The ~~how~~mining ~~Niagara~~operation ~~Mohawk’s transmission system~~ is ~~managed~~complete ~~under~~and the ~~NYISO~~site ~~and “FERC~~has ~~Order 2000” regarding a December 1999 FERC proposal to create a~~been ~~regional~~reclaimed ~~transmission~~and ~~organization~~restored.
AsNM ~~of January 1~~Properties, ~~2001, Niagara~~Inc. ~~Mohawk~~- ~~had~~engages ~~approximately~~in ~~50,500~~real ~~circuit~~estate ~~miles~~development ~~of transmission~~ and ~~distribution~~ ~~lines~~divestiture ~~for electric delivery. Evaluation~~ of ~~these facilities~~ ~~relative~~property toformerly ~~NYISO,~~owned ~~Northeast~~by ~~Power~~the ~~Coordinating~~Company. NM ~~Council~~Properties, ~~and~~Inc. ~~North~~owns ~~American~~several ~~Electric~~subsidiaries ~~Reliability Organization, planning criteria~~ and ~~anticipated~~has ~~Niagara Mohawk~~interests ~~internal~~in ~~and~~several ~~external~~joint ~~demands~~ventures isin ancarrying ~~ongoing~~out ~~process intended to maintain the reliability of electric service while minimizing the capital requirements for expansion of these facilities. Niagara Mohawk continually reviews the adequacy of~~ its ~~electric delivery facilities and establishes capital~~ ~~requirements to support new load growth~~activities.
~~GAS~~NM ~~SUPPLY~~Receivables - facilitates the sale of an undivided interest in a designated pool of customer receivables, including accrued unbilled revenues. NM Receivables, LLC is owned by the Company (over 99.99 percent) and by NM Receivables Corp. II, which is a wholly owned subsidiary of the Company. See Item 8. Financial Statements and Supplementary Data, - Note A. Summary of Significant Accounting Policies and Note I. Commitments and Contingencies.

~~The~~NATIVE ~~majority~~AMERICAN of Niagara Mohawk’s gas sales are for residential and commercial space and water heating. Consequently, the demand for natural gas by Niagara Mohawk’s customers is seasonal and influenced by weather factors. Niagara Mohawk purchases its natural gas for sale to its customers under firm supply agreements and under term purchase agreements with portfolio managers. The gas is transported under firm transportation contracts with interstate pipelines. A one-year portfolio management service and purchase of natural gas agreement with Southern Company Energy marketing entity (currently known as Mirant Americas Energy Marketing, L.P.) (“Mirant”) became effective November 1, 2000. Mirant exercised its option to extend this agreement one additional year. Niagara Mohawk is currently planning for supplies subsequent to November 2002. MATTERS

~~GAS~~There ~~DELIVERY~~are five Native American Nations with reservations located in the vicinity of the Company’s service territory and facilities. The Company has held discussions and has been involved in legal proceedings with Native American Nations involving the Company’s high voltage transmission facilities on Nation lands, provision of electric service to customers on Nation lands, and the Nations’ land claims.In June 2000, the Company entered into a 40-year agreement with the Seneca Nation to settle issues related to approximately 50 miles of high voltage transmission and distribution facilities located on the Seneca Nation’s Cattaraugus and Allegheny Reservations. The Company has entered into federally approved Electric Service Agreements with the Onondaga, Tuscarora and Seneca-Tonawanda Nations governing the provision of electric service to customers on their lands. The Company intends to seek similar agreements with the Oneida and Mohawk Nations to supplement existing federally approved agreements. The Company’s facilities are affected by land claim litigation involving the Cayuga, Oneida, Mohawk and Seneca Nations. A court has awarded damages to the Cayuga Nation that are payable by the State of New York. The land claim matters involving the Cayuga, Oneida, Mohawk and Seneca Nations have not been completely and finally resolved, although the St. Regis Mohawk Tribe recently entered into a Memorandum of Understanding with New York State that could lead to resolution of the Mohawk’s land claims against the Company. The Company continues to monitor the land claim litigation and, where necessary, defends its interests.

~~Niagara~~MORTGAGE Mohawk sells, distributes and transports natural gas to a geographic territory that generally extends from Syracuse to Albany. The northern reaches of the system extend to Watertown and Glens Falls. Not all of Niagara Mohawk’s distribution areas are physically interconnected with one another by its own facilities. Presently, 9 separate distribution areas are connected directly with Dominion Transmission, Inc., an interstate natural gas pipeline regulated by the FERC, via 19 delivery stations. Niagara Mohawk also has two direct connections with Iroquois Gas Transmission, one with Empire State Pipeline, and one with Tennessee Gas Pipeline. LIENS

~~ENVIRONMENTAL~~Substantially ~~MATTERS~~all of the Company’s operating properties are subject to a mortgage lien securing its mortgage debt.ITEM 3. LEGAL PROCEEDINGSThe Company settled material litigation in April 2003 and currently has three material proceedings pending in addition to the environmental matters described in Note I to the financial statements in Item 8.

Fourth Branch Associates Mechanicville: In November 1993, ~~General. Niagara~~Fourth Branch Associates Mechanicville (“Fourth Branch”) filed an ~~Mohawk’s~~action ~~operations~~against the Company and ~~facilities~~several ~~are~~of ~~subject~~its toofficers ~~numerous~~and ~~federal,~~employees in New York state court. The lawsuit arose from the Company’s termination of a ~~and~~contract ~~local~~for ~~laws~~Fourth Branch to operate and ~~regulations~~maintain ~~relating~~a tohydroelectric plant the Company ~~environment~~owned ~~including~~in the town of Halfmoon, ~~among~~New York. Fourth Branch’s ~~other~~complaint ~~things,~~also ~~requirements~~alleged ~~concerning~~claims ~~air~~based ~~emissions,~~on ~~water~~the ~~discharges,~~inability ~~site~~of Fourth Branch and the ~~remediation,~~Company ~~hazardous~~to ~~materials~~agree ~~handling,~~on ~~waste~~terms ~~disposal~~for ~~and~~the ~~employee~~purchase ~~health and~~of ~~safety.~~power ~~While~~from ~~Niagara~~a ~~Mohawk~~new ~~devotes~~facility ~~considerable~~that Fourth ~~resources~~Branch hoped to ~~environmental~~construct at the Mechanicville site. The Parties agreed ~~compliance~~to ~~and~~settle ~~promoting~~the ~~employee~~case ~~health~~in ~~and~~April ~~safety,~~2003. Under the ~~impact~~settlement, ofthe ~~future~~Company will ~~environmental~~transfer ~~health~~the ~~and~~hydroelectric ~~safety~~plant ~~laws~~to Fourth Branch, subject to regulatory approval, and ~~regulations~~will onmake ~~Niagara~~lump-sum ~~Mohawk~~payments ~~cannot~~to ~~be predicted~~Fourth ~~with~~Branch ~~certainty.~~and its bank in an aggregate amount that is immaterial to the Company.

In Alliance ~~compliance~~for ~~with environmental~~Municipal ~~statutes~~Power ~~and~~v. ~~consistent~~New ~~with~~York ~~its~~State ~~strategic~~Public ~~philosophy, Niagara~~Service ~~Mohawk~~Commission: On ~~performs~~February ~~environmental~~17, ~~investigations~~2003, ~~and~~the ~~analyses~~Alliance ~~and~~for ~~installs,~~Municipal asPower ~~required,~~(“AMP”) ~~pollution~~filed ~~control~~with ~~equipment,~~the ~~including,~~New ~~among~~York ~~other~~state ~~things,~~court ~~effluent monitoring~~a ~~instrumentation~~petition ~~and~~for ~~materials~~review ~~storage/handling facilities designed to~~of ~~prevent~~decisions orby ~~minimize~~the ~~releases~~New ofYork ~~potentially~~State ~~harmful~~Public ~~substances.~~Service ~~Expenditures~~Commission ~~for~~(the ~~environmental~~“PSC”) ~~matters~~that ~~for~~maintain ~~calendar~~the ~~year~~PSC’s ~~2001~~established ~~totaled~~policy ~~approximately~~of ~~$44.7~~using ~~million,~~average ofdistribution ~~which~~rates ~~approximately~~when ~~$3.6~~calculating ~~million~~the ~~was~~exit ~~capitalized~~fees asthat ~~pollution control~~may orbe ~~plant~~charged ~~environmental surveillance equipment and approximately $41.1~~to ~~million~~municipalities ~~was~~that ~~charged~~seek to ~~operating~~leave ~~expense~~the ~~for~~Niagara ~~remediation,~~Mohawk ~~operation~~system ~~of environmental~~and ~~monitoring~~establish ~~and~~their own ~~waste~~municipal ~~disposal~~light ~~programs~~departments. Changes ~~Expenditures~~in the methodology for ~~2002~~the ~~are~~calculation ~~estimated~~of tothe ~~total~~exit ~~$35.1~~fee ~~million,~~are ofnot ~~which~~likely ~~$0.5~~to ~~million~~have isa ~~expected~~material toeffect beon Niagara ~~capitalized~~Mohawk’s ~~and~~financial ~~$34~~statements.6 However, ~~million~~AMP’s ~~charged~~petition tofor ~~operating~~review also ~~expense.~~challenges ~~Anticipated expenditures~~the ~~for~~lawfulness ~~2003~~of ~~are~~Niagara ~~estimated~~Mohawk’s tocollection ~~total~~of ~~$35.0~~exit ~~million~~fees from departing municipalities, regardless of ~~which~~the ~~$0.5~~methodology used to calculate ~~million~~those isfees. If ~~expected~~the court were to berule ~~capitalized~~that ~~and~~Niagara ~~$34.5~~Mohawk ~~million~~is ~~charged~~not toauthorized ~~operating~~to ~~expense.~~collect ~~The~~exit ~~expenditures~~fees, ~~for~~and ~~2002~~if ~~and~~the ~~2003~~AMP ~~include~~communities ~~the~~proceeded ~~estimated~~with ~~costs~~their ~~for~~plans to ~~Niagara~~municipalize ~~Mohawk’s~~power, ~~expected~~the ~~proportionate~~Company ~~share~~could ofexperience ~~the~~a ~~costs~~significant ~~for~~shortfall ~~site~~of ~~investigation~~revenue. In ~~and~~addition, ~~remediation~~such ofa ~~waste~~ruling ~~sites~~could ~~discussed~~encourage ~~under “Solid/Hazardous~~other ~~Waste”~~municipalities ~~below~~to consider municipalizing. The ~~Costs~~Company ~~for~~would ~~site~~seek ~~investigation~~to ~~and~~defer any lost revenue for ~~remediation~~eventual ~~are~~recovery ~~included~~from inits ~~operating~~remaining ~~expense~~customers pursuant to the ~~extent~~terms ~~actual~~of ~~costs~~its ~~equal~~rate ~~the~~plan. Niagara ~~amount~~Mohawk ~~provided~~believes ~~for~~that init ~~rates;~~has ~~variations~~strong ~~are~~defenses ~~deferred~~to ~~for future~~AMP’s ~~recovery/pass-back~~petition toand ~~customers~~is contesting the petition vigorously.

New York State v. Niagara Mohawk ~~believes~~Power itCorp. et al.: On January is10, ~~probable~~2002, ~~that~~New ~~costs~~York ~~associated~~State ~~with~~filed ~~environmental~~a ~~compliance~~civil ~~will~~action ~~continue~~against tothe Company and NRG in befederal ~~recovered~~district ~~through~~court ~~the~~in ~~ratemaking~~Buffalo, ~~process.~~New ~~For~~York, afor ~~discussion~~alleged violations of the ~~circumstances~~federal ~~regarding~~Clean ~~Niagara~~Air ~~Mohawk’s~~Act ~~continued~~and ~~ability~~related tostate ~~recover~~environmental ~~these~~laws at the Dunkirk and ~~types~~Huntley ofpower ~~expenditures~~plants, which the Company sold in ~~rates~~1999 to NRG and its affiliates (collectively, ~~see~~“NRG”). The ~~Part~~State IIalleged, ~~Item~~among 8.other ~~Financial~~things, ~~Statements~~that between 1982 and ~~Supplementary~~ ~~Data~~1999, -the ~~Note~~Company 3.modified ~~Rate~~the ~~and~~two ~~Regulatory~~plants ~~Issues~~55 times without obtaining proper preconstruction permits and ~~Contingencies~~implementing proper pollution equipment controls. The state sought, among other relief, statutory penalties under the Clean Air Act, which could have a maximum value of $25,000 to $27,500 per day per violation.

The Company and NRG moved to dismiss the complaint on statute of limitations and other grounds in 2002, and on March 27, 2003, the court granted the motions in part, holding that the violations of the Clean Air Act. prior to ~~See~~November ~~Item~~1996 3.were ~~Legal~~barred ~~Proceedings~~by the federal five-year statute of limitations, ~~for~~and that arelated ~~discussion~~state statutory violations prior to November 1999 were barred by the state three-year statute of limitations. This eliminated the Company’s potential ~~liability~~exposure ~~for~~to statutory daily penalties prior to these dates. At the ~~past~~same ~~operations~~time, ofthe ~~Huntley~~court ~~and~~preserved the State’s non-regulatory ~~Dunkirk~~claims ~~fossil~~against ~~generating~~the ~~stations~~Company and dismissed NRG from the suit.

~~ISO~~On ~~14001. Niagara~~April ~~Mohawk’s~~25, ~~Investment~~2003, ~~Recovery~~the ~~facility~~State ~~was~~filed ~~registered~~a tomotion ~~ISO~~for ~~14001~~leave into amend the ~~October~~complaint ~~1999~~to ~~and~~assert ~~Niagara~~new ~~Mohawk~~claims ~~continues~~against toboth ~~maintain~~the ~~this~~Company ~~registration.~~and ~~Niagara~~NRG for unspecified ~~Mohawk~~amounts. Among ~~has~~other ~~also~~things, ~~reviewed~~the ~~its~~state ~~entire~~is ~~transmission~~seeking ~~and~~to ~~distribution~~reassert ~~system~~daily inviolations ~~preparation~~of ~~for~~the ~~ISO~~Clean ~~14001~~Air ~~registration.~~Act ~~Niagara~~going ~~Mohawk’s~~back ~~position~~to ~~has been~~1982, the time period covered by its original ~~and~~complaint. On ~~continues~~May to30, be2003, ~~that~~the anCompany ~~effective~~filed ~~environmental~~papers ~~management~~in ~~system~~opposition isto the ~~necessary~~State’s topetition. Oral ~~prudently~~argument ~~manage~~has ~~environmental~~been ~~issues~~scheduled ~~and~~for ~~minimize~~July ~~environmental liabilities~~2, 2003.
~~Solid/Hazardous~~Prior Waste. The public utility industry typically utilizes and/or generates in its operations a broad range of hazardous and potentially hazardous wastes and by-products. Niagara Mohawk believes it is handling identified wastes and by-products in a manner consistent with federal, state and local requirements and has implemented an environmental audit program to ~~identify~~the ~~any~~commencement ~~potential areas~~ of ~~concern~~the ~~and~~enforcement ~~aid in compliance with such requirements. Niagara Mohawk is also currently conducting a program to investigate and remediate~~action, ason ~~necessary, to~~July ~~meet current environmental standards~~13, ~~certain properties associated with former gas manufacturing and other properties which Niagara Mohawk has learned may be contaminated with industrial waste~~2001, ~~as well as investigating identified~~the ~~industrial~~Company ~~waste~~filed ~~sites~~a asdeclaratory tojudgment ~~which~~action itin ~~may~~New beYork ~~determined~~State ~~that~~court ~~Niagara~~in ~~Mohawk has~~Syracuse ~~contributed.~~against ~~Niagara~~NRG ~~Mohawk~~seeking ~~has~~a ~~also~~ruling ~~been advised~~ that ~~various~~NRG ~~federal,~~is ~~state~~responsible ~~or local~~for ~~agencies believe certain properties require investigation and has prioritized~~ the ~~sites~~costs ~~based~~of ~~on available information in order to enhance the~~pollution ~~management~~controls ~~of investigation~~ and ~~remediation,~~mitigation ifthat ~~necessary.~~might ~~See~~result ~~Part~~from ~~II,~~the ~~Item~~State’s 8.enforcement ~~Financial Statements and Supplementary Data - Note 8~~action. As ~~Commitments and Contingencies, “Environmental Contingencies,” for~~ a ~~discussion~~result of ~~the sites~~NRG’s ~~which~~voluntary ~~are~~bankruptcy ~~Niagara Mohawk owned. Niagara Mohawk has recorded a total environmental liability of $305 million~~petition, offiled ~~which~~in ~~$191 million relates to owned~~New ~~sites~~York ~~and~~federal ~~$114~~court ~~million~~for ~~relates~~bankruptcy toon ~~non-owned~~May ~~sites~~14, as2003, ~~further~~the ~~discussed below.~~Company’s ~~The~~declaratory ~~potential~~judgment ~~high~~action ~~end of the range~~ is ~~presently estimated at approximately $525 million~~stayed.

~~With~~ ~~respect to sites not owned by~~ Niagara Mohawk, ~~but~~Power ~~for~~Corp. ~~which~~v. itHuntley ~~has~~Power ~~been~~L.L.C., orDunkirk ~~may~~Power L.L.C. beand ~~associated~~Oswego ~~as a PRP~~Harbor, ~~Niagara~~L.L.C.: The ~~Mohawk~~Company ~~has~~is ~~recorded~~engaged in a ~~liability of $114 million, representing its~~collection ~~current~~litigation ~~estimate~~to ofrecover ~~its~~bills ~~share~~for ofstation ~~the~~service ~~total~~rendered ~~cost~~ to ~~investigate~~the ~~and~~owners ~~remediate~~of three ~~these~~power ~~sites.~~plants (the ~~Niagara~~“Plants”), ~~Mohawk~~which ~~has~~the ~~denied~~Company ~~any~~sold ~~responsibility~~in ~~for~~1999 ~~certain of these~~to ~~PRP~~three ~~sites~~affiliates ~~and~~of isNRG: Huntley ~~contesting~~Power L.L.C., ~~liability~~Dunkirk ~~accordingly~~Power L.L.C. and ~~Twelve~~Oswego ofHarbor, L.L.C. (collectively, the ~~PRP sites are~~“Defendants”). ~~included~~According onto the ~~National~~Company’s ~~Priorities~~records, ~~List~~as ~~(“NPL”).~~of ~~Niagara~~March ~~Mohawk estimates~~31, ~~that~~2003, ~~its~~the ~~share~~Defendants owed of the ~~liability~~Company ~~for~~approximately ~~these~~$33 12million. After ~~sites~~suit iswas ~~not~~filed, ~~material~~the ~~and~~parties ~~has~~agreed ~~included~~to stay the ~~amount~~litigation into permit the ~~determination~~FERC ofto ~~the~~try ~~amounts~~to ~~accrued.~~resolve the dispute.

~~Estimates~~As ofnoted ~~Niagara Mohawk’s~~above, ~~potential~~NRG ~~liability~~filed ~~for~~a ~~sites~~voluntary ~~not~~bankruptcy ~~owned~~petition byin ~~Niagara~~New ~~Mohawk,~~York federal ~~but~~court for ~~which~~ itbankruptcy ~~has~~on ~~been~~May ~~identified as an alleged PRP~~14, ~~have been derived by estimating the total cost of site cleanup and then applying Niagara Mohawk’s contribution factor to that estimate where appropriate~~2003. The ~~Estimates~~Company ofhas ~~the~~received ~~total~~approval ~~cleanup costs are determined by using all available information~~ from ~~investigations~~ ~~conducted by Niagara Mohawk and other parties, negotiations with other PRPs and, where no other basis is available at~~ the ~~time~~bankruptcy ofcourt ~~estimate, the EPA figure for average cost~~ to ~~remediate~~move aforward ~~site listed on the NPL as disclosed~~ in ~~the~~its ~~Federal~~FERC ~~Register of June 23, 1993 (58 Fed~~proceeding. Any ~~Reg. 119). A contribution~~FERC ~~factor~~decision iswould calculated when there is a reasonable basis for it, that uses either a pro rata share based upon the total number of PRPs named or otherwise identified or the percentage agreed upon with other PRPs through steering committee negotiations or by other means. In some instances, Niagara Mohawk has been unable to determine ~~a contribution factor and has included in~~ the ~~amount~~Company’s ~~accrued the~~ability ~~total estimated costs~~ to ~~remediate~~charge the ~~sites. Actual Niagara Mohawk~~Defendants ~~expenditures~~ for ~~these~~station ~~sites~~service ~~are~~electricity ~~dependent~~post-bankruptcy, ~~upon~~but the ~~total~~collection ~~cost~~ of ~~investigation and remediation and~~ the ~~ultimate determination of Niagara Mohawk’s share of~~ ~~responsibility~~outstanding ~~for~~station ~~such~~service ~~costs~~bills as ~~well~~of as the ~~financial~~bankruptcy ~~viability~~filing ofdate ~~other~~will ~~PRPs~~be ~~since~~governed ~~cleanup~~by ~~obligations~~the ~~are~~bankruptcy ~~joint~~court ~~and several~~proceedings.

~~Based~~ITEM on4. SUBMISSION ~~significant progress~~OF ~~made~~MATTERS onTO ~~several~~A ~~key~~VOTE ~~sites~~OF ~~during 2001, Niagara Mohawk anticipates~~SECURITY ~~spending~~HOLDERSNo ~~approximately~~matters ~~$30~~were ~~million~~submitted ~~in 2002~~ to ~~continue~~a ~~similar~~vote ~~progress~~of ~~in addressing~~security ~~the site priorities and schedules jointly established with the DEC.~~holders Induring ~~May 1997,~~ the ~~DEC~~last ~~executed~~quarter ~~an Order~~ of ~~Consent (~~the ~~“1997~~fiscal ~~Order”) which serves to keep the annual cash requirement for certain site investigation and remediation (“SIR”) level at approximately $15 million per~~ year~~, contingent~~ ~~upon~~ended ~~DEC~~March ~~acceptance of proposed site priorities and schedules. As executed~~31, ~~the 1997 Order expands the scope of the original 1992 Order, which covered 21 former MGP sites, to encompass most additional sites with which Niagara Mohawk has been associated~~2003. The agreement is supported by the decision analysis approach, which Niagara Mohawk and the DEC will continue to revise on an annual basis to address SIR progress and site priorities relative to establishing the annual cost cap, as well as estimating Niagara Mohawk’s liability for these sites. The Saratoga Springs and Harbor Point MGP sites are being investigated and remediated pursuant to separate regulatory Consent Orders with the EPA and the DEC, respectively. However, the annual costs associated with the remediation of these sites are included in the cash requirements under the amended 1997 Order.

~~Power~~PART Choice and Niagara Mohawk’s gas settlement provide for the recovery of SIR costs during the settlement periods. Niagara Mohawk believes future costs, beyond the settlement periods, will continue to be recovered in rates. Based upon this assessment, a regulatory asset has been recorded in the amount of $305 million, representing the future recovery of estimated remediation obligations accrued to date. As a result, Niagara Mohawk does not believe SIR costs will have a material adverse effect on its results of operations or financial condition. See also Part II~~, Item 8. Financial Statements and Supplementary Data - Note 3. Rate and Regulatory Issues and Contingencies.~~

~~RESEARCH~~ITEM 5. MARKET FOR THE REGISTRANTS’ COMMON EQUITY AND ~~DEVELOPMENT~~RELATED STOCKHOLDER MATTERSThe common stock of the Company is held solely by Niagara Mohawk Holdings, Inc., and therefore indirectly by National Grid USA and National Grid Transco plc. There is no public trading market for the Company’s common stock, and the Company sold no equity securities during the period covered by this Annual Report. For information about the Company's payment of dividends and restrictions on those payments, see Item 6, Selected Financial Data, and Item 8, in the Notes to the Financial Statements.

~~Niagara~~ITEM Mohawk maintains a research and development (“R&D”) program aimed at improving the delivery and use of energy products and finding practical applications for new and existing technologies in the energy business6. SELECTED ~~R&D~~CONSOLIDATED ~~expenditures~~FINANCIAL ~~in 1999 through 2001 were not material to Niagara Mohawk’s results of operations or financial condition.~~ DATA

~~CONSTRUCTION~~The ~~PROGRAM~~following tables set forth selected financial information for the Company for the year ended March 31, 2003, the sixty days ended March 31, 2002, thirty days ended January 30, 2002, three months ended March 31, 2001, and each of the four years during the period ended December 31, 2001, which have been derived from the financial statements of the Company, and should be read in connection therewith.

On January 31, 2002, the Company was acquired by National Grid in a ~~See~~purchase ~~Part~~business IIcombination recorded under the “push-down” method of accounting, resulting in a new basis of accounting for the “successor” period beginning January 31, 2002. Information relating to all “predecessor” periods prior to the acquisition is presented using the Company’s historical basis of accounting. As discussed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, ~~“ Financial~~and ~~Position,~~Item ~~Liquidity~~8. ~~and~~Financial ~~Capital~~Statements ~~Resources”~~ and ~~Part~~Supplementary ~~II,~~Data ~~Item~~- Notes 8.to Consolidated Financial Statements, ~~and~~the ~~Supplementary~~following ~~Data~~selected financial data -for ~~Note~~the 8.Company ~~Commitments~~may ~~and~~not ~~Contingencies~~be indicative of the Company’s future financial condition, ~~“Construction~~results ~~Program~~of operations or cash flows.”

INSURANCE

		Year Ended	60 Day Period	30 Day Period	Three months
(in 000's except		March 31,	Ended March	ended January	ended March	Year Ended December 31,
per share data)		2003	31, 2002	30, 2002	31, 2001	2001	2000	1999	1998
		(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)	(Predecessor)	(Predecessor)	(Predecessor)

Operating Revenues		$ 4,019,450	$ 689,705	$ 362,622	$ 1,179,706	$ 4,114,713	$ 3,865,949	$ 3,827,340	$ 3,826,373

Net Income (Loss)		125,871	30,646	(20,941)	34,010	19,358	(27,646)	(9,661)	(147,894)

Income (loss) from		*	*	*	*	*	*	*	(0.89)
	continuing operations per
	average common share

Total assets		12,243,759	12,101,588	**	12,037,039	11,436,554	12,270,324	12,418,508	13,835,987

Long-term debt		3,953,989	4,146,642	**	4,674,004	4,419,822	4,678,963	5,042,588	6,417,225

Mandatorily redeemable		-	-	**	53,750	50,700	53,750	61,370	68,990
	preferred stock

Dividends paid per		*	*	*	*	*	*	*	-
	common share

As* All of ~~January 31, 2002,~~ the ~~date~~ ofCompany’s ~~the~~shares ~~merger, National Grid has insurance related to directors and officers liability. This coverage insures the directors and officers against obligations incurred as a result~~ of ~~their~~common ~~indemnification~~stock byare ~~National~~owned ~~Grid. The coverage also insures the directors and officers against liabilities for which they may not be indemnified~~ by ~~National~~its ~~Grid, except for a dishonest act or~~parent ~~breach of trust. This policy also covers the directors and officers of National Grid’s subsidiaries. In addition~~company, ~~Niagara Mohawk purchased run-off coverage (insurance coverage purchased to cover claims that may be reported subsequent to the merger date but pertain to events that occurred prior to such date)~~therefore, ~~for~~dividend ~~a six-year~~information ~~term, to protect former directors~~ and ~~officers~~per ofshare ~~Niagara~~data ~~Mohawk~~is ~~from~~not ~~events that occurred prior to the merger date~~relevant.

~~EMPLOYEE~~** Balance ~~RELATIONS~~Sheet information as of the 30 day period ended January 30, 2002 is not provided.

~~Niagara~~ITEM ~~Mohawk’s work force at December 31, 2001 numbered approximately 6,200, of whom approximately 72 percent were union members~~7. ~~It is estimated that approximately 80 percent of Niagara Mohawk~~ MANAGEMENT’sS ~~total~~DISCUSSION ~~labor~~AND ~~cost~~ANALYSIS ~~is applicable to operation and~~OF ~~maintenance~~FINANCIAL CONDITION ~~and~~AND ~~approximately~~RESULTS 20OF ~~percent is applicable to construction and other accounts.~~ OPERATIONS

~~All~~MERGER ofWITH ~~Niagara Mohawk’s~~NATIONAL non-supervisory production and clerical workers subject to collective bargaining are represented by the International Brotherhood of Electrical Workers (“IBEW”). On July 13, 2001, Niagara Mohawk and the IBEW agreed on a 3-year, 4-month labor agreement, which provided for wage increases of approximately 3.25 percent to 3.75 percent over the next 3 years. GRID

On January 31, 2002, the acquisition of Holdings by National Grid was ~~Niagara~~completed ~~Mohawk~~for a value of approximately $3.0 billion in cash and American Depositary Shares. The acquisition is being accounted for by the purchase method, the application of which, including the recognition of goodwill, is being recognized on the books of the Company, the most significant subsidiary of Holdings. The merger transaction resulted in approximately $1.2 billion of goodwill. The purchase accounting method required the Company to revalue its assets and liabilities at their fair value. This revaluation resulted in an increase to the Company’s ~~work~~pension and postretirement benefit liability in ~~force~~the ~~decreased~~amount ~~during~~of ~~2001~~approximately as$440 million, with a ~~result~~corresponding offsetting increase to a regulatory asset account. See “Merger Rate Plan”, below, for a discussion of the ~~sale~~anticipated future results on the Company. See Item 8. Financial Statements and Supplementary Data, - Note H. Pension and Other Retirement Plans for a discussion of the ~~nuclear~~Company’s ~~generation~~pension and ~~plants~~postretirement benefit plans.

~~SEASONALITY~~ VERO

In January ~~See~~2002, ~~Item~~the 2Company made a voluntary early retirement offer (“VERO”) to 302 eligible employees in targeted areas where significant workforce reductions were necessary in the combined organization, primarily corporate administrative functions such as finance, human resources, legal and information technology. Eligible ~~Properties~~employees were non-union ~~Electric~~employees ~~Delivery~~in ~~Properties~~the ~~and~~targeted functions ~~Part~~who IIwill be age 55 with at least ten years of pension service by March 31, ~~Item~~2004. The 8Company sets the actual retirement dates for individuals based on operational needs. Retirement ~~Financial~~dates ~~Statements~~will conclude no later than April 1, 2004.The number of eligible employees that accepted the VERO was 267 and most ~~Supplementary~~retired ~~Data~~by -June ~~Note~~30, 122002. Under the Merger Rate Plan, the Company is ~~Quarterly~~allowed ~~Financial~~to ~~Data~~record ~~(unaudited)~~a regulatory asset for separation and early retirement costs. The amortization of such regulatory asset is occurring over ten years, with approximately 69 percent of the amortization of the regulatory asset occurring within the first three years. On January 31, 2002, the Company recorded a regulatory asset of $53 million related to the VERO. This regulatory asset had a balance of $30 million at March 31, 2003.

~~ITEM~~REGULATORY 2.AGREEMENTS ~~PROPERTIES~~AND THE RESTRUCTURING OF THE REGULATED ELECTRIC UTILITY BUSINESS

~~ELECTRIC~~Merger ~~SUPPLY~~Rate ~~PROPERTIES~~Plan. On November 28, 2001, the PSC approved the Merger Rate Plan. This rate plan became effective on January 31, 2002, the closing of the merger. Key terms of the plan are as follows:

~~Niagara~~ Net ~~Mohawk: During~~customer ~~1999,~~savings ~~Niagara~~of ~~Mohawk~~approximately ~~completed~~$1 ~~the~~billion ~~sale~~over ofthe ~~its~~next ~~coal-fired generation~~ten ~~plants~~years, ~~its~~compared ~~hydroelectric~~with ~~plants,~~rates ~~and~~projected ~~its~~without ~~oil~~the ~~and gas-fired plant in Oswego~~merger. ~~Niagara~~ This ~~Mohawk~~includes ~~completed~~a ~~the sale of its oil and gas-fired generation plant at~~$152 ~~Albany~~million ~~during~~reduction ~~2000~~in ~~and~~delivery ~~its~~charges 25compared ~~percent~~to ~~interest~~rates approved in the ~~Roseton Steam Station in~~ ~~early~~Company’s ~~2001.~~Power InChoice ~~the~~rate ~~fourth quarter 2001~~agreement, ~~Niagara~~followed ~~Mohawk~~by ~~completed~~stabilized ~~the sale of its~~delivery ~~nuclear~~charges ~~generation~~for ~~assets.~~ten ~~See~~years, ~~Part~~subject ~~II,~~to ~~Item.~~limited 7adjustments. This ~~Management’s~~equals ~~Discussion~~an expected ~~and~~reduction ~~Analysis~~in ofthe ~~Financial~~Company ~~Condition~~electricity ~~and~~delivery ~~Results~~rates of ~~Operations~~more -than ~~Regulatory~~eight percent, ~~Agreements~~which ~~and~~results ~~the~~in ~~Restructuring~~a ofprojected ~~the~~five ~~Regulated~~percent ~~Electric~~decrease ~~Utility~~in ~~Business,~~overall ~~for~~electricity bills, including a ~~further~~projected ~~discussion~~commodity ofcost, ~~the~~which ~~sales~~will ofcontinue ~~Niagara~~to ~~Mohawk’s~~be ~~generation~~borne ~~assets.~~by customers.
~~Niagara~~ Price-stabilized ~~Mohawk~~commodity ~~does~~service ~~not~~for ~~own~~residential ~~any other electric supply facilities~~ and ~~meets~~commercial customers ~~its~~for ~~electric~~several ~~supply requirements~~years, ~~through~~giving ~~PPAs~~those ~~and~~customers ~~open~~significant ~~market~~protection ~~purchases~~ from severe fluctuations in the ~~NYISO~~generation marketplace.
~~ELECTRIC~~ Agreement ~~DELIVERY~~to ~~PROPERTIES~~forgo the collection of approximately $850 million in nuclear-related costs that otherwise would have been collected in rates.
~~Niagara~~ Permitted ~~Mohawk: As~~recovery of ~~January~~and ~~31,~~a ~~2002~~return on the remaining MRA regulatory asset, ~~Niagara~~which ~~Mohawk’s~~consists ~~electric~~of ~~delivery~~recoverable ~~transmission~~costs ~~and~~to ~~distribution~~terminate ~~systems~~or ~~were~~amend ~~composed~~IPP ~~of:~~contracts under the MRA.
• Agreement ~~748~~to ~~substations~~expand ~~with~~the aCompany’s ~~rated~~annual ~~transformer~~upstate ~~capacity~~New ofYork economic ~~approximately~~development ~~22,800,000~~efforts ~~kilo-voltamperes~~by ~~• approximately 9,400 circuit miles of overhead and underground transmission lines • approximately 36,100 conductor miles of overhead distribution lines • about~~ $12.5~~,000~~ ~~cable miles of underground distribution cables~~million.
~~Only~~ The aextension ~~part of Niagara Mohawk’s transmission and distribution lines are located on property owned~~ by ~~Niagara~~16 ~~Mohawk.~~months ~~With~~of ~~respect~~the toexisting ~~Niagara~~multi-year ~~Mohawk’s~~gas ~~transmission~~rate settlement ~~and distribution lines that are located on property not owned by Niagara Mohawk~~agreement, ~~Niagara~~resulting ~~Mohawk’s~~in ~~practice~~a isfreeze toin ~~obtain~~natural ~~right~~gas ofdelivery ~~way~~rates through ~~agreements~~December 2004.
~~There~~ Extension isof ~~seasonal~~the ~~variation~~Low inIncome ~~electric~~Customer Assistance ~~customer~~Program ~~load. In 2000~~ and ~~2001,~~introduction ~~Niagara~~of ~~Mohawk’s~~a ~~maximum~~special ~~hourly~~low-income ~~demand occurred in the summer~~rate.
~~The~~ Establishment ~~electric~~of ~~system~~a ~~of Niagara~~Service ~~Mohawk~~Quality isAssurance ~~directly~~Program ~~interconnected~~that ~~with~~calls ~~other~~for up ~~electric~~to ~~utility~~$24 ~~systems~~million in ~~New~~ ~~York,~~annual ~~Massachusetts,~~penalties ~~Vermont~~or ~~and~~more ~~Pennsylvania,~~under ~~and~~certain ~~indirectly~~conditions, ~~interconnected~~if ~~with~~defined ~~most~~customer ofservice ~~the~~goals ~~electric~~are ~~utility~~not ~~systems through the Eastern Interconnection of the United States~~achieved.
~~GAS~~ The ~~DELIVERY~~continuation of the stranded cost recovery provisions under Power Choice with slight modifications.
~~Niagara~~ The ~~Mohawk~~sharing ~~distributes gas~~with ~~purchased~~customers ~~from~~50 ~~suppliers~~percent ~~and transports gas owned by others. As~~ of ~~December 31,~~cumulative ~~2001,~~earnings ~~Niagara~~in ~~Mohawk’s~~excess ~~natural gas delivery system was comprised~~ of ~~approximately~~ ~~8,300 miles of pipelines and mains. Only a part of these natural~~an ~~gas pipelines and mains are located on property owned by Niagara Mohawk~~11.75 ~~With respect~~percent toreturn ~~natural gas pipelines and mains that are not located~~ on ~~property owned~~common ~~by Niagara Mohawk, Niagara Mohawk’s practice is to obtain right of way agreements~~equity.

~~SUBSIDIARIES~~Although rates will be lower under the Merger Rate Plan, the Company believes cost savings from the merger should enable it to improve its operating results.Generation Asset Sales. Federal and state mandates have encouraged the separation of generation from transmission and distribution in order to promote competition and reduce prices to customers. In accordance with these mandates, the Company has divested all of its generation plants and operates primarily in the transmission and distribution sectors. In 1999, the Company completed the sale of its coal-fired generation plants, its hydro generation plants, and its oil and gas-fired generation plant at Oswego for $860 million. In 2000, the Company completed the sale of its oil and gas-fired plant at Albany for $48 million. In January 2001, the Company completed the sale of its 25 percent interest in the Roseton Steam Station for approximately $84 million. In November 2001, the Company sold its nuclear assets to Constellation for approximately $603 million. The Company also executed PPAs with the buyers of the formerly owned fossil and hydro assets, which are designed to help the Company meet rate reduction and price cap commitments as well as expected demand as the provider of last resort. The Company also signed PPAs with Constellation to purchase energy at negotiated prices through 2011 and revenue sharing agreements for ten years thereafter. See Item 8. Financial Statements and Supplementary Data, Note B. Rate and Regulatory Issues and Contingencies, Note I. Commitments and Contingencies, and Note J. Derivatives and Hedging Activities, for a further discussion of the terms of these agreements.Following write-offs agreed to by the Company, the PSC Order approved the sale of the nuclear assets and provided for the deferral and future recovery of the remaining nuclear stranded costs. The Company began to amortize the regulatory asset related to the loss on the sale of the nuclear assets immediately subsequent to such sale. Prior to implementation of the Merger Rate Plan, the Company had a regulatory asset of $1,074.6 million for the net loss on the sale of its nuclear generation assets. Under the Merger Rate Plan, the Company agreed to forgo collection of approximately $850 million in nuclear-related costs that otherwise would have been collected in rates. The nuclear regulatory asset that remained after such a write-off is included in the Company’s balance sheet as part of “Merger rate plan stranded costs.” FERC Proceedings. The FERC is contemplating major changes to the regulatory structure that governs the Company’s business. Several proposals are under consideration, any of which may affect how the Company does business. The Company cannot predict which or how many of the proposals the FERC will adopt or in what form, or whether they will have a material impact on the Company’s financial position or results of operations.Regional Transmission Organizations: The FERC has indicated that it wants regional transmission organizations ("RTOs") formed that would cover a larger geographic area than independent system operators ("ISOs"). In response to an order by the FERC, participants in the ISO New England (“ISO-NE”), the New York ISO, and the Pennsylvania-New Jersey-Maryland ISOs took part in a mediation to establish an RTO. The FERC has not yet ruled on the mediator’s report. Pending the FERC’s ruling, transmission owners, including the Company, have been working to develop an alternative RTO structure. It is not clear what structure will emerge from these negotiations or what the geographic scope will be of the RTO in which the Company participates. In August 2002, the New York and New England ISOs filed a proposal with the FERC to form an RTO but withdrew it in November 2002 after several parties, including National Grid USA, filed protests.Standard Market Design: In July 2002, the FERC issued a formal notice of proposed rulemaking ("NOPR") on standard market design ("SMD"). The proposed rules address transmission pricing and planning, the role of merchant transmission, and other issues that would directly affect the Company. The FERC issued a White Paper on April 28, 2003 outlining a proposed wholesale power market platform that it would require in any final rules in this proceeding. The White Paper embodies FERC's response to the comments that it received in this proceeding. FERC states that it intends to issue a rule requiring that public utilities join independent entities (either an RTO or an ISO) that would be responsible for transmission service, tariff design, system operations and markets within a region. States would have a significant role in regional transmission planning, tariff design and in ensuring resource adequacy. Transmission owners that are market participants would have limited authority to manage transmission. Independent transmission companies may manage a broader set of functions.

The FERC has also proposed that it assume jurisdiction over transmission ~~Niagara~~rates ~~Mohawk~~to retail customers. In prior orders, the FERC has held that deliveries at retail will continue to be subject to state-approved retail charges as well as the ~~following~~FERC-approved ~~subsidiaries:~~transmission rate, even if the delivery is made over transmission facilities. The introduction of an independent entity with its own transmission tariff would require coordination between the state and federally approved charges to avoid bypass of costs embedded in such state approved charges.

~~(a)~~In ~~NM Uranium~~addition, ~~Inc.~~to -the ~~has~~extent anthe ~~interest~~Company inwishes ato ~~uranium~~pursue ~~mining~~opportunities related ~~operation~~to intransmission ~~Live Oak County~~projects, ~~Texas,~~the ~~which~~FERC isrulings ~~now~~ in the ~~process~~SMD ofproceeding ~~reclamation~~ and other ~~restoration.~~proceedings ~~(b)~~may NMlimit ~~Properties,~~the ~~Inc.~~Company's -ability ~~engages~~to indo ~~real estate development and divestiture of property formerly owned by Niagara Mohawk~~so. NMThe ~~Properties,~~Company ~~Inc.~~cannot predict ~~owns~~when ~~several subsidiaries and has interests in several joint ventures in carrying out its activities. (c) NM Receivables - facilitates~~ the ~~sale~~FERC ofwill anissue ~~undivided~~final ~~interest~~rules inon ~~a designated pool of customer receivables~~SMD, ~~including~~or ~~accrued~~in ~~unbilled~~what ~~revenues. NM Receivables~~form, ~~LLC~~or isif ~~owned~~they will byhave ~~Niagara~~a ~~Mohawk~~material ~~(over~~impact ~~99.99~~on ~~percent)~~the ~~and~~Company’s byfinancial NMposition ~~Receivables~~or ~~Corp. II, which is a wholly owned subsidiary~~ results of ~~Niagara Mohawk~~operations.

~~NATIVE~~On ~~AMERICAN~~July ~~MATTERS~~12, 2002, the U.S. Court of Appeals issued an order concerning Pennsylvania-New Jersey-Maryland ISO’s relationship with its transmission owners. This order was favorable precedent to the Company because it suggested that transmission owners that join ISOs still maintain significant authority to propose transmission rates and to withdraw from such ISOs. On December 19, 2002 and May14, 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 more recent decision will stand, but the uncertainty surrounding this issue will likely affect the Company’s relationship with the NYISO and with any future RTO. 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.PSC Issues. In connection with an audit performed by PSC Staff, the Company reached a settlement with the Staff that resolves all issues associated with its pension and other postretirement benefit obligations for the period prior to the acquisition of the Company by National Grid. The settlement is subject to approval by the full New York State Public Service Commission. Among other things, the settlement covers the funding of the Company’s pension and post-retirement benefit plans. Under the settlement, the Company agreed to provide $100 million of tax-deductible funding by April 30, 2003 (which it funded in March 2003), and an additional $209 million, on a tax-deductible basis, by December 31, 2011. The Company will earn a rate of return of at least 6.60 percent on any portion of the $209 million that it funds before December 31, 2011, plus 80 percent of the amount by which the rate of return on the pension and post-retirement benefit funds exceeds 5.34 percent. This settlement resolves all PSC Staff audit issues related to the pre-acquisition period with the exception of certain gas deferrals and a Staff review of a pending Company compliance filing related to the sale of the Nine Mile Nuclear Station. As part of the Company's ongoing reconciliation of commodity costs and revenues, the Company has identified several adjustments and included them in filings with the PSC. Specifically, the Company has requested recovery of $36 million of commodity costs associated with the under-reconciliation of New York Power Authority (“NYPA”) hydropower revenues in its commodity adjustment clause, and is proposing to refund $24 million associated with other revenues that were not included in the commodity adjustment reconciliation. In addition, the Company has filed a modification to its tariff and a proposal to refund an additional $7 million associated with the recovery of other NYPA hydropower costs. These filings are pending before the PSC, and the Company cannot predict the outcome of the filings.

There are five Native American Nations with reservations located in the vicinity of Niagara Mohawk’s service territory and facilities. Niagara Mohawk has held discussions and has been involved in legal proceedings with Native American Nations involving Niagara Mohawk’s high voltage transmission facilities on Nation lands, provision of electric service to customers on Nation lands, and the Nations’ land claims. OTHER

InChange ~~June~~of ~~2000,~~Fiscal ~~Niagara Mohawk~~Year. At ~~entered into a 40-year agreement with~~ the ~~Seneca~~time ~~Nation to settle issues related to approximately 50 miles~~ of ~~high voltage transmission facilities located on~~ the ~~Seneca~~merger ~~Nation’s Cattaraugus and Allegheny Reservations. Niagara Mohawk has entered into Electric Service Agreements~~ with ~~the Onondaga,~~National ~~Tuscarora~~Grid, ~~and Seneca-Tonawanda Nations governing~~ the ~~provision~~Company ofchanged ~~electric service~~its tofiscal ~~customers~~year onfrom ~~their~~a ~~lands.~~calendar ~~These~~year ~~agreements~~ending ~~are pending federal~~December ~~approval.~~31 ~~Niagara Mohawk intends~~ to ~~seek~~a ~~similar~~fiscal ~~agreements~~year ~~with~~ending ~~the~~March ~~Oneida and Mohawk Nations to supplement existing federally approved agreements~~31. The ~~Niagara Mohawk’s~~Company ~~facilities~~made ~~are~~this ~~affected~~change byin ~~land~~order ~~claim litigation involving the~~to ~~Cayuga,~~align ~~Oneida,~~its ~~Mohawk~~fiscal ~~and~~year ~~Seneca~~with ~~Nations. A court has awarded damages to the Cayuga Nation~~ that ~~are~~of ~~payable~~its bynew ~~the~~parent ~~State~~company, ofNational ~~New York~~Grid. The ~~land claim matters~~ ~~involving~~Company’s ~~the~~first ~~Cayuga,~~new ~~Oneida,~~full ~~Mohawk~~fiscal ~~and~~year ~~Seneca~~began ~~Nations~~on ~~have~~April ~~not~~1, ~~been~~2002 ~~completely~~ and ~~finally~~ended ~~resolved. Niagara Mohawk will continue to monitor the land claim~~on ~~litigation~~March ~~and where necessary defend its interests~~31, ~~but is unable to predict the timing or outcome of these matters~~2003.

~~MORTGAGE~~CRITICAL ~~LIENS~~ACCOUNTING POLICIES

There are certain critical accounting policies that are based on ~~Substantially~~assumptions and conditions that if changed could have a material effect on the financial condition, results of operations and liquidity of the Company. The following accounting policies are particularly important to the financial condition and results of operations of the Company: regulatory accounting (including the collection of purchase power costs through the commodity adjustment clause and purchased gas through the gas cost collection mechanism), goodwill accounting and derivative accounting. Regulatory AccountingElectric utilities are subject to certain accounting standards that are generally not applicable to other business enterprises. The Company applies the provisions of Statement of Financial Accounting Standards (“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 Financial Accounting Standards Board (“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 PSC to recover through its Competitive Transition Charges (“CTCs”) substantially all of the costs ~~Niagara~~associated ~~Mohawk~~with its former generating business not recovered through the divestiture. The CTC is a mechanism that was established in the Company’s Power ~~operating~~Choice ~~properties~~agreement to recover stranded costs from customers. 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 the Merger Rate Plan, the Company will earn a return on all of its regulatory assets. In the event the Company determines, as a result of lower than expected revenues or higher than expected costs, or both, that its net regulatory assets are ~~subject~~not probable of recovery, it can no longer apply the principles of SFAS No. 71 and would be required to record an after-tax, non-cash charge against income for any remaining unamortized regulatory assets and liabilities. If the Company could no longer apply SFAS No. 71, the resulting charge would be material to the Company’s reported financial condition and results of operations and adversely affect the Company’s ability to pay dividends.Under the Merger Rate Plan, the Company’s remaining electric business (electric transmission and distribution) continues to be rate-regulated on a ~~mortgage~~cost-of-service ~~lien~~basis and, ~~securing~~accordingly, the Company continues to apply SFAS No. 71 to these businesses. Also, the Company’s IPP contracts, including those restructured under the MRA, as well as the PPAs entered into in connection with the generation divestiture, continue to be the obligations of the regulated business.DerivativesThe FASB issued SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), as amended, which the Company adopted on January 1, 2001. SFAS No. 133 requires that companies identify all derivative instruments in use, record all derivatives on the balance sheet as assets or liabilities measured at fair value and adjust the fair value at each financial reporting period. Depending on the use of the derivative and its ~~mortgage~~qualification as ~~debt~~a hedge, the changes in fair value either will be recorded directly in earnings or will be deferred and matched with the settlement of the transaction being hedged. The Company’s derivatives are listed on the Consolidated Balance Sheets as “Derivative Instruments” or “Current liabilities—other.” Upon implementation of SFAS No. 133, the Company designated several financial instruments as derivatives and qualified certain of these instruments as hedges. Those derivative instruments that did not qualify for hedge accounting were the result of regulatory rulings and therefore, the earnings impact of the adoption of SFAS No. 133 was offset by regulatory assets or liabilities as directed by SFAS No. 71. The result was no impact on earnings for the adoption of SFAS No. 133 by the Company.Revenue RecognitionThe Company bills its customers on a monthly cycle basis at approved tariffs based on energy delivered and a minimum customer service charge. Revenues are determined based on these bills plus an estimate for unbilled energy delivered between the cycle billing date and the end of the accounting period. The Company estimates unbilled revenues using the prior month’s average daily revenue for each billing cycle.GoodwillThe company applies the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (FAS 142). In accordance with FAS 142, goodwill must be reviewed for impairment at least annually. 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.PensionsThe Company has recognized an additional minimum pension liability of $269 million on its balance sheet reflecting an underfunded pension obligation. The Company would normally record a charge to other comprehensive income as an offset to this entry. However, due to the nature of its rate plan the Company has not charged other comprehensive income but has instead recorded a regulatory asset.For further discussion of Critical Accounting Policies see Item 7A. Quantitative and Qualitative Disclosures About Market Risk, Item 8. Financial Statements and Supplementary Data, Note A. Summary of Significant Accounting Policies, Note B. Rate and Regulatory Issues and Contingencies and Note J. Derivatives and Hedging Activities.

~~ITEM~~RESULTS 3.OF ~~LEGAL PROCEEDINGS~~OPERATIONS

The following discussion and analysis highlights items that ~~For~~significantly affected the Company’s operations during the year ended March 31, 2003, the three months ended March 31, 2002 and 2001, and the twelve-month periods ended December 31, 2001 and 2000. See “Merger Rate Plan” for a ~~detailed~~further discussion of how the closing of the merger with ~~additional~~National ~~legal~~Grid ~~proceedings,~~will ~~see~~impact ~~Part~~the ~~II,~~future ~~Item~~results 8of the Company. Results ~~Financial~~of operations ~~Statements~~through January 30, 2002 reflect the Power Choice rate plan and the ~~Supplementary~~Company’s ~~Data~~generation -assets ~~Note~~sales. Reported 8earnings under Power Choice were substantially depressed as a result of the regulatory treatment of the MRA regulatory asset. Information ~~Commitments~~relating ~~and~~to ~~Contingencies,~~all “~~Environmental~~predecessor” periods ~~Contingencies~~prior to the acquisition is presented using the Company’s historical basis of accounting.” It ~~See~~should also be read in conjunction with Item 18. ~~Business~~Financial Statements -and ~~Environmental~~Supplementary ~~Matters~~Data, -and other financial and statistical ~~Solid/Hazardous~~information ~~Waste,~~appearing ~~Item~~elsewhere 2in this report.The ~~Properties~~Company -now ~~Native~~reports results ~~American~~on ~~Matters,~~a ~~and~~fiscal ~~Part II~~year ending March 31, ~~Item~~which 7has affected comparability to prior results. To ~~Management~~assist in the comparability of the Company’s ~~Discussion~~financial results and ~~Analysis~~discussions, results of ~~Financial~~operations ~~Condition~~for the three months ended March 31, 2002 include results for the 30 day period of the predecessor and the 60 day ~~Results~~period of ~~Operations~~the -successor ~~Regulatory~~and ~~Agreements~~are designated as “combined.” Management has based its discussion and analysis of results of operations for the ~~Restructuring~~three month period ending March 31, 2002 as compared to the three month period ending March 31, 2001 on the combined results of operations for the three ~~Regulated~~month ~~Electric~~period ~~Utility~~ending ~~Business~~March 31, 2002.EARNINGSNet income ~~Niagara~~for ~~Mohawk~~the twelve months ended March 31, 2003 increased approximately $107 million compared to the twelve months ended December 31, 2001. This increase is primarily ~~unable~~due to ~~predict~~the implementation of the Merger Rate Plan, a nuclear write-off ~~ultimate~~in ~~disposition~~2001 and the sale of the ~~matters~~Company’s ~~referred~~generation tobusiness, ~~below~~which was completed in 2001. Under Inthe ~~addition~~Merger Rate Plan, ~~consistent~~the Company has lowered delivery ~~with~~rates ~~its~~leading ~~rate~~to ~~agreements~~lower operating revenues. However, ~~Niagara~~this ~~Mohawk~~has ~~believes~~been ~~that~~offset itby lower isoperating ~~probable~~expenses ~~that~~as ita result of merger savings, the sale of the ~~will~~generation bebusiness ~~able~~and lower interest expense due to ~~recover~~refinancing ~~prudently~~and ~~incurred~~the continuing ~~expenditures~~repayment of debt.Net income for the three months ended March 31, 2002 was approximately $24 million lower than the three month period ended March 31, 2001. A decline in ~~cost-~~operating income due to the effect a warm winter had on the gas business and increased other operation and maintenance costs was partially offset by lower interest expense due to the repayment of~~-service~~ ~~based~~debt during ~~rates~~2002.Net ~~See~~income ~~also~~for ~~Part~~the IItwelve months ended December 31, ~~Item~~2001 8increased approximately $47 million compared with the twelve months ended December 31, 2000. This ~~Financial~~is ~~Statements~~primarily ~~and~~due ~~Supplementary~~to ~~Data~~lower -interest expense due to the repayment of ~~Note~~debt 3during 2001. Earnings ~~Rate~~for ~~and~~2001 ~~Regulatory~~also ~~Issues~~reflect the effects the generation asset sale namely increased purchased electricity offset by lower depreciation, property tax, labor and ~~Contingencies~~fuel expenses.REVENUESElectric revenues decreased $82 million in the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001. The table below details components of this fluctuation.

1. On June 22, 1993, Niagara Mohawk and 20 other industrial entities, as well as the former owner/operator of the Pfohl Brothers Landfill near Buffalo, New York, were sued in New York State Supreme Court, Erie County, by a group of residents living in the area surrounding the landfill. The plaintiffs seek compensation for alleged economic loss and property damage claimed to have resulted from exposure to contamination associated with the landfill. In addition, since January 18, 1995, Niagara Mohawk has been named as a defendant or third party defendant in a series of toxic tort actions filed in federal or state courts in the Buffalo area. These actions allege exposure on the part of plaintiffs or plaintiffs’ decedents to toxic chemicals associated with the landfill, resulting in the alleged causation of property damage and/or physical injury. The plaintiffs seek compensatory and punitive damages. Niagara Mohawk has filed answers responding to the claims put forth in these suits, denying liability as to any of the claimed conditions or damages and will vigorously defend against each claim. Niagara Mohawk is unable to predict at this time the probable outcome of these proceedings, which at present remain in the discovery stage (although the discovery process has been held in abeyance pending the outcome of the appeal of dismissal of certain of the actions on a statute of limitations basis). Niagara Mohawk, through participation in the Pfohl Brothers Landfill Steering Committee, is participating in the implementation of a remedial program as required pursuant to a DEC administrative order on consent executed in April 2001. Remedial construction is expected to be complete by the end of July 2002, with total construction costs projected to reach $23.5 million. In the context of a formal remedial cost allocation proceeding conducted on behalf of the Committee, it has been determined that Niagara Mohawk’s potential contribution of industrial wastes to the landfill was minor. Further, it is Niagara Mohawk’s position that any materials attributable to Niagara Mohawk, which may have been disposed of at the landfill, are not causally related to any physical condition alleged or other harm alleged to have been incurred by plaintiffs in the various lawsuits associated with the landfill. Niagara Mohawk does not believe that the outcome of these proceedings will have a material adverse effect on its results of operations or financial condition. 2. In November 1993, Fourth Branch Associates Mechanicville (“Fourth Branch”) filed an action against Niagara Mohawk and several of its officers and employees in the New York State Supreme Court, seeking compensatory damages of $50 million, punitive damages of $100 million, and injunctive and other related relief. The lawsuit grows out of Niagara Mohawk’s termination of a contract for Fourth Branch to operate and maintain a hydroelectric plant Niagara Mohawk owned in the town of Halfmoon, New York. Fourth Branch’s complaint also alleges claims based on the inability of Fourth Branch and Niagara Mohawk to agree on terms for the purchase of power from a new facility that Fourth Branch hoped to construct at the Mechanicville site. In January 1994, Niagara Mohawk filed a motion to dismiss Fourth Branch’s complaint. By order dated November 7, 1995, the Court granted Niagara Mohawk’s motion to dismiss the complaint in its entirety. Fourth Branch filed an appeal from the Court’s order. On January 30, 1997, the Appellate Division modified the November 7, 1995 court decision by reversing the dismissal of the fourth and fifth causes of action set forth in Fourth Branch’s complaint. Discovery proceedings have been completed. Fourth Branch filed a Trial Term Note of Issue on August 30, 2001 placing the case on the Albany County Supreme Court trial calendar. A pre-trial conference was held on October 9, 2001 and the case was assigned a trial date of April 1, 2002 in the Albany County Supreme Court. A motion for summary judgment on behalf of Niagara Mohawk was filed on November 15, 2001. Fourth Branch has opposed the motion and filed a cross-motion for summary judgment on its breach of contract claim. A pre-trial conference was held in Albany County Supreme Court on March 19, 2002. In view of the fact that the motion for summary judgment was still pending, the court rescheduled the trial date to June 24, 2002. Niagara Mohawk and Fourth Branch had also entered into negotiations under a FERC mediation process. As a result of these negotiations, Niagara Mohawk had proposed to sell the hydroelectric plant to Fourth Branch for an amount which would not be material. In addition, the proposal included a provision that would require the discontinuance of all litigation between the parties. Attempts to implement this proposal were unsuccessful, and Niagara Mohawk informed FERC that its participation in the mediation efforts was concluded. On January 14, 1997, the FERC Administrative Law Judge issued a report to FERC recommending that the mediation proceeding be terminated. During July 1998, Fourth Branch commenced a condemnation proceeding in Federal District Court to obtain title to the project property and also made a unilateral offer of settlement before FERC. Niagara Mohawk served an answer with various affirmative defenses. On July 30, 1998, Fourth Branch moved for Summary Judgment. Niagara Mohawk opposed Fourth Branch’s motion and cross-moved for summary judgment in favor of Niagara Mohawk. The Court granted Niagara Mohawk’s motion for summary judgment on September 1, 1999. On September 10, 1999, Fourth Branch filed an amended unilateral offer of settlement with FERC. On September 30, 1999, Niagara Mohawk filed its response and objection to the amended offer of settlement. On November 23, 1999, FERC issued a comprehensive order rejecting Fourth Branch’s unilateral offer of settlement, dismissing Fourth Branch’s complaint of anti-competitive conduct against Niagara Mohawk and determining that there has been an implied surrender by Fourth Branch and Niagara Mohawk of the FERC license for the Mechanicville Project. On December 23, 1999, Fourth Branch filed a petition for rehearing of the Commission’s decision. On March 16, 2000, FERC denied the petition for rehearing. On April 21, 2000, Fourth Branch filed an appeal of FERC’s decision to the United States Court of Appeals in Washington, D.C. On June 19, 2001, the Court of Appeals denied Fourth Branch’s appeal. FERC has also initiated proceedings related to site closure and restoration plans, or alternatives thereto. On February 28, 2002, FERC issued an order accepting license surrender and directing the implementation of Niagara Mohawk’s closure plan. Niagara Mohawk is unable to predict the ultimate disposition of the lawsuit and FERC case referred to above. 3. On May 25, 2000, the DEC issued an air pollution notice of violation to Niagara Mohawk regarding the operation of its two formerly owned coal-fired generation plants (Huntley and Dunkirk). The notice of violation was also issued to NRG Energy, Inc. (“NRG”), the current owner and operator of both plants. The notice alleges violations of the federal Clean Air Act and the New York State Environmental Conservation Law resulting from the alleged failure of the companies to obtain permits for plant modifications and the alleged failure to install air pollution control equipment. While no specific relief was sought in the notice of violation, the DEC and the New York State Attorney General indicated in meetings with Niagara Mohawk and NRG that they will be seeking substantial fines against Niagara Mohawk and NRG as well as the imposition of pollution controls. The New York State Attorney General also indicated that they will be pursuing mitigation of alleged environmental harm. It is Niagara Mohawk’s position that the cost of pollution controls and mitigation should be borne by NRG. In May 2001, the New York State Attorney General advised Niagara Mohawk and NRG of its intent to file suit, alleging that the plants are in violation of the federal Clean Air Act. On July 13, 2001, Niagara Mohawk filed a declaratory judgment action against NRG in New York State Supreme Court. Niagara Mohawk is seeking a declaratory judgment that NRG is responsible for any control upgrades and mitigation resulting from the above-referenced enforcement action. On August 31, 2001, NRG filed its answer, affirmative defenses and counterclaims in response to Niagara Mohawk’s complaint seeking a declaratory judgment. On September 24, 2001, Niagara Mohawk served its reply to NRG’s counterclaims. The litigation is presently in the discovery phase. On January 10, 2002, the state of New York and Erin M. Crotti, as Commissioner of the DEC, filed on a civil action against Niagara Mohawk and NRG Energy in U.S. District Court for the Western District of New York for alleged violations of the federal Clean Air Act at the Dunkirk and Huntley power plants. NMPC is in the process of reviewing the complaint. A response from Niagara Mohawk is due by March 29, 2002. Niagara Mohawk is unable to predict whether or not the results of this enforcement action will have an adverse material effect on its financial position and results of operation or whether Niagara Mohawk's action against NRG will be successful.

Change in Electric Revenue from the twelve months ended
December 31, 2001 to March 31, 2003
(In Millions)

	Retail sales		$ (1)
	Sales for resale		(61)
	Transmission wheeling		(23)
	Other		3
		Total	$ (82)
			=========

~~ITEM~~The decrease in sales for resale is primarily attributable to lower sales to the NYISO. Transmission wheeling revenue was lower primarily due to lower NYISO Transmission Congestion Contracts (“TCC”) auction revenues. Although there was almost no change in retail sales, revenues increased due to higher delivery only revenue by $88 million which were offset by lower electric rates under the Merger Rate Plan.Electric revenues decreased $1 million in the three months ended March 31, 2002 as compared to the same period in the 2001 and increased $186 million in the calendar year 2001 as compared to the same period in 2000. Electric revenues decreased in the three months ended March 31, 2002 as compared to the same period in 2001 primarily as a result of lower sales to ultimate customers due to the warmer weather. In addition, transmission revenues decreased $9 million primarily due to the introduction of the transmission revenue adjustment mechanism on September 1, 2002, which reduced transmission revenues by $7 million. These decreases were partially offset by an increase in distribution of energy of $19 million; higher electric rates since September 2001 of $21 million since the commodity cost reflected in rates was higher, partially offset by lower delivery rates; an increase in systems benefit charge revenue recoveries of $6 million and an increase in unbilled revenues of $6 million. In accordance with Power Choice and the Merger Rate Plan, the Company recognizes changes in accrued unbilled revenue in its results of operations. The systems benefits charge is offset in other operation and maintenance expense. The decrease in electric sales to ultimate consumers and the increase in distribution of energy reflect the growing number of customers that purchase electricity from other suppliers. The increase in electric revenues in 2001 as compared to 2000 is primarily due to an increase in sales for resale of $118 million as a result of higher sales to the NYISO; higher overall rates since September 2001 of $37 million since the commodity cost reflected in rates was higher, partially offset by lower delivery rates; an increase in miscellaneous revenues of $27 million; an increase in transmission revenues of $11 million and an increase in the systems benefit charge revenue recoveries of $24 million.Electric kilowatt-hour sales were approximately 38.8 billion for the twelve months ended March 31, 2003, 9.4 billion and 9.3 ~~SUBMISSION~~billion OFfor ~~MATTERS~~the TOthree Amonths ~~VOTE~~ended March OF31, ~~SECURITY~~2002 ~~HOLDERS~~and the same period in 2001, respectively, and 39.9 billion in the calendar year 2001, and 36.3 billion in the calendar year 2000.Electric deliveries for the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001 decreased 1.1 billion KWh. The decrease is primarily due to a decrease in sales for resale of 2.1 billion KWh as a result of lower sales to the NYISO and lower sales to commercial and industrial customers of 2.1 billion KWh offset by increased residential sales of ..6 billion KWh and an increase in delivery only of energy of 2.5 billion KWh. Electric deliveries for the three months ended March 31, 2002 as compared to the same period in 2001 increased 0.1 billion KWh and increased 3.6 billion KWh in the calendar year 2001 as compared to the same period in 2000. The increase in the three months ended March 31, 2002 as compared to the same period in 2001 is primarily due to an increase in sales for resale of 0.7 billion KWh as a result of higher sales to the NYISO and an increase in distribution of energy of 0.2 billion KWh, partially offset by a decrease in sales to ultimate customers of 0.7 billion KWh primarily due to the milder weather. The increase in calendar year 2001 is primarily due to an increase in sales for resale of 4.1 billion KWh as a result of higher sales to the NYISO, partially offset by a decrease in sales to ultimate customers of 0.3 billion KWh due to the milder weather in 2001 as compared to 2000.Gas revenues decreased $13 million for the twelve-months ended March 31, 2003 compared to the twelve-months ended December 31, 2001 primarily due to a decrease in the commodity cost of purchased gas offset somewhat by an increase in delivery revenue. The primary reason for the increase in gas delivery revenue is higher rates which reflect the inclusion of the state income tax. The decrease in the cost of purchased gas is explained below under “gas purchased” expense. The table below details components of the gas revenue fluctuation.

NoChange ~~matters~~in ~~were~~Gas ~~submitted~~Revenue tofrom athe ~~vote~~twelve-months ofended ~~security~~December ~~holders~~31, ~~during~~2001 ~~the~~to ~~fourth~~March ~~quarter~~31, of2003 ~~2001.~~ (In Millions)

EXECUTIVE OFFICERS OF REGISTRANTS


Cost of Purchased Gas		$ (26)
Delivery Revenue		18
Other		(5)
	Total	$ (13)
		========

Gas revenues decreased $127 million in the three months ended March 31, ~~All~~2002 ~~executive~~from ~~officers~~the comparable period in 2001 due to lower gas prices being passed through to customers and milder weather in 2002. Gas revenues increased $63 million in the calendar year 2001 primarily as a result of ~~Niagara~~higher ~~Mohawk~~gas prices being passed through to customers in early 2001, despite overall milder weather in 2001.The commodity cost of purchased gas has no impact on the Company’s net income because the actual commodity costs are ~~elected~~passed through to customers on ana ~~annual~~one-to-one basis. Gas atsales for the ~~organizational~~twelve months ~~meeting~~ended March 31, 2003, excluding transportation of customer-owned gas and spot market sales, were 69 million Dth, a 5.8 percent increase from the twelve-months ~~Board~~ended December 31, 2001. The increase was primarily due to the impacts of ~~Directors~~weather oras ~~upon~~offset by migration to delivery only service. Gas sales in the ~~filling~~calendar year 2001, excluding transportation of customer-owned gas and spot market sales, were 64 million Dth. Gas sales in the three months ended March 31, 2002, excluding transportation of customer-owned gas and spot market sales, were 28 million Dth, a ~~vacancy~~19.6 ~~There~~percent ~~are~~decrease nofrom ~~family~~the same period in ~~relationships~~2001. The ~~between~~decrease ~~any~~was primarily due to milder weather in the three months ended March 31, 2002 as compared to the same period in 2001.Gas sales in the calendar year 2001, excluding transportation of customer-owned gas and spot market sales, were 64 million Dth, a 9.7 percent decrease from 2000. The decrease in gas sales is primarily attributable to milder weather in 2001 as compared to 2000. Gas delivered was also negatively impacted by a decrease in transportation volumes of 14 million Dth as a result of customers purchasing less gas from other gas providers.OPERATING EXPENSESThe Company’s electricity purchased increased $290 million for the ~~executive~~year ~~officers~~ended March 31, 2003 as compared to the year ended December 31, 2001, $52 million in the three months ended March 31, 2002 as compared to the same period in 2001 and $160 million in calendar year 2001 as compared to calendar year 2000, primarily as a result of the timing of the various sales of the Company’s generation assets. The ~~There~~Company now purchases all of its load requirement through the NYISO, or through other parties under long-term PPAs (for a discussion of the portion of the purchases that are hedged, nosee ~~arrangements~~Item 7A. Quantitative and Qualitative Disclosure about Market Risk - or“Electricity ~~understandings~~Price ~~between~~Risk”). Although ~~any~~the prices the Company must pay for electricity are higher than the fuel costs incurred when the assets were owned, the Company avoids operating costs from running these plants, including labor, fuel, real estate taxes, and depreciation.Significantly higher natural gas prices impacted the Company’s fuel and purchased power costs during the third and fourth quarters of 2000 and in early 2001, principally because restructured contracts with IPPs began indexing to natural gas prices in July 2000. Fuel and purchased power costs were also higher in the ~~officers~~third ~~listed~~and fourth ~~below~~quarters of 2000 and in early 2001 because of an indexed contract with the new owner of the Albany generating station and an indexed contract with an IPP not part of the MRA. The Company’s continued 25 percent ownership in the Roseton generating station also increased fuel and purchased power costs in 2000. The Roseton generating station was sold in January 2001. The Albany and Roseton stations are both fueled by oil or natural gas. With respect to its exposure to the restructured contracts with the IPPs and the Albany contract, the Company takes steps to hedge against further volatility in natural gas prices, largely by purchasing New York Mercantile Exchange (“NYMEX”) gas futures contracts. On September 1, 2001, the rate plan changes under the Power Choice agreement allowed for the pass-through of most commodity-related costs to customers. This pass-through of commodity costs to customers continues under the Merger Rate Plan.IPP purchases decreased by $17 million in the three months ended March 31, 2002 as compared to the same period in 2001, since the Company entered into an agreement with one IPP that reduced the amount of energy it had to buy from them. In the three months ended March 31, 2001, the Company paid that IPP $18 million. The Company did not make any ~~other~~payments ~~person~~to ~~pursuant~~that particular IPP in the same period in 2002. IPP purchases were lower in calendar year 2001 as compared to ~~which~~2000 hedue to a decrease in hydro IPP production as a result of a reduction in water flow because of drier weather. The change in the deferral for electricity purchased is due to the regulatory treatment of the hydro PPA as discussed in Item 8. Financial Statements and Supplementary Data - Note B. Rate and Regulatory Issues and Contingencies.The Company had no fuel for electric generation expense in either the twelve-months ended March 31, 2003 or ~~she~~the ~~was~~three ~~selected~~months ended March 31, 2002 because it had sold all of its generation assets in earlier periods. Fuel for electric generation decreased $37 million in calendar year 2001 as ancompared ~~officer~~to 2000, primarily as a result of the timing of the various sales of the Company’s generation assets. In addition, generation from the Company’s nuclear plants was reduced due to an extended outage of one of the nuclear plants in 2001.

Executive	Age at 12/31/2001	Current and Prior Positions	Date Commenced
William E. Davis	59	Resigned (became Chairman of National Grid USA and Executive Director of National Grid Group plc)	February 2002
		Chairman of the Board and Chief Executive Officer	May 1993
Darlene D. Kerr	50	Resigned (became President of National Grid USA Service Company, Inc. and Senior Vice President & Chief Administrative Officer-National Grid USA)	February 2002
		President and Chief Operating Officer	December 2000
		Executive Vice President and Chief Operating Officer	April 1999
		Executive Vice President-Energy Delivery	September 1998
		Senior Vice President-Energy Distribution	December 1995
David J. Arrington	50	Retired	March 2002
		Senior Vice President-Human Resources & Chief Administrative Officer (Niagara Mohawk)	April 1999
		Senior Vice President-Human Resources	December 1990
Thomas H. Baron	57	Retired	March 2002
		Senior Vice President-Field Operations	October 1998
		Vice President-Fossil/Hydro Generation and Environmental Affairs	April 1998
		Vice President-Fossil/Hydro Generation	May 1991
Edward J. Dienst	48	Resigned (became Senior Vice President of New England Operations)	February 2002
		Senior Vice President-Asset Management & Energy Delivery	April 1999
		Senior Vice President-Customer Delivery & Asset Management	October 1998
		Vice President-Electric Delivery	May 1996
William F. Edwards	44	Senior Vice President-National Grid USA and President-Niagara Mohawk Power Corporation	September 1997
		Senior Vice President and Chief Financial Officer	September 1997
		Vice President-Financial Planning	December 1995
John H. Mueller	55	Retired	December 2001
		Senior Vice President and Chief Nuclear Officer	January 1998
		Site Vice President of Commonwealth Edison’s Zion Plan	August 1996
Gary J. Jesmain	54	Senior Vice President-Business Services	February 2002
		Regional Manager-Central Region	February 1998
		General Manager-Central Region	September 1996
Clement E. Nadeau	50	Senior Vice President-Operations	February 2002
		Vice President-Electric Delivery	December 1998
		Vice President-Power Transactions and Planning	May 1991
Anthony C. Pini	49	Senior Vice President-Customer Service	February 2002
		President-NEES Communications	November 1997
		Vice President-Customer Service-New England Electric System	June 1993
Theresa A. Flaim	52	Vice President-Energy Supply, Rates and Regulatory Proceedings	March 2002
		Vice President-Strategic Planning	May 1999
		Vice President-Corporate Strategic Planning	May 1994
Kapua A. Rice	50	Corporate Secretary	September 1994
Steven W. Tasker	44	Senior Vice President-Distribution Finance New York	February 2002
		Vice President-Controller	December 1993
Edward A. Capomacchio	55	Vice President-Controller	February 2002
		Assistant Controller-New England Power Service Company	June 1998
		Director-Internal Audit	May 1994

The Company’s gas purchased expense decreased approximately $26 million for the year ended March 31, 2003 as compared to the year ended December 31, 2001. The decrease is a result of lower gas prices in the current period partially offset by increased sales attributable to the colder winter weather conditions than in the comparable prior period. Quantities purchased and withdrawn from storage were up 5.7 million Dth. The Company’s net cost per Dth, as charged to expense, including the effects of the gas cost deferral, decreased to $5.57 in the twelve-months ended March 31, 2003 from $6.45 for the twelve-months ended December 31, 2001.

Gas purchased expense decreased $120 million in the three months ended March 31, 2002 as compared to the same period in 2001 primarily as a result of lower natural gas prices. Dth purchased and withdrawn from storage were down 0.4 million Dth. The Company’s net cost per Dth, as charged to expense, including the effects of the gas commodity cost adjustment clause, decreased to $3.97 in the three months ended March 31, 2002 from $7.53 the same period in 2001.

The Company’s gas purchased expense increased $62 million in 2001, primarily as a result of higher natural gas prices which more than offset reduced sales volumes. Dth purchased and withdrawn from storage were down 16.1 million Dth. The Company’s net cost per Dth, as charged to expense, including the effects of the gas commodity cost adjustment clause, increased to $6.45 in calendar year 2001 from $4.42 in calendar year 2000.

For a discussion of hedging of gas purchases, see Item 7A. Quantitative and Qualitative Disclosures about Market Risks – “Gas Supply Price Risk.”

~~PART~~Other IIoperation and maintenance expense decreased $112 million for the year ended March 31, 2003 as compared to the year ended December 31, 2001. The decrease is primarily attributable to the sale of its generation assets, especially its nuclear generation, in that the labor, fuel, and real estate taxes for these generation assets are no longer paid for. Expense was also reduced due to lower transmission costs from fewer TCCs purchased from NYISO and merger integration savings in the current period. TCCs confer the right to collect or obligation to pay congestion charges for a single megawatt of energy transmitted between two geographic locations.Other operation and maintenance expense for the Company had increased $27 million in the three months ended March 31, 2002 as compared to the same period in 2001, primarily as a result of increased employee welfare expense primarily due to separation costs of $7 million, increased pension and other postretirement benefits expense of $14 million, increased compensation accruals of $6 million, incremental merger related costs of approximately $11 million, incremental storm expense of $14 million and a higher systems benefit charge of $6 million. The systems benefits charge is offset in electric revenues. These increases were partially offset by lower nuclear operation expense of $36 million as a result of the sale of the nuclear assets. Other operation and maintenance expense for the Company has increased $65 million in 2001, primarily as a result of an increase in transmission expense of $34 million in part due to TCCs purchased through the auction process conducted by the NYISO, an increase in bad debt expense of $8 million which reflects the impact of the higher natural gas prices being passed on to customers, a higher systems benefit charge of $23 million, higher compensation accruals of $13 million and higher pension expense of $19 million. The systems benefits charge and the TCC expense are both offset in electric revenues. The incremental merger related costs for 2001 were approximately $4 million. In addition, the insurance proceeds and disaster relief associated with the 1998 ice storm restoration effort was $6 million in 2001 as compared to $30 million in 2000. Offsetting these increases were lower injuries and damages expense of $12 million, lower employees welfare expense of $6 million, lower customer services system expense of $7 million, lower non-nuclear operation and maintenance expense as a result of the sale of the non-nuclear assets of $16 million and lower nuclear operation and maintenance expense, net of deferrals and amortizations, of $21 million.In 2001, the Company recorded a non-cash write-off of $123 million before tax, which is reflected on the disallowed nuclear investment costs line item in accordance with the PSC Order approving the sale of the nuclear assets. Amortization of stranded costs decreased $243 million for the twelve-months ended March 31, 2003 as compared to the twelve-months ended December 31, 2001, decreased by $27 million in the three months ended March 31, 2002 as compared to the same period in 2001 and increased by $18 million in 2001 and increased $12 million for 2000. The decreases are from the difference in rate plans. Under Power Choice, the MRA regulatory asset was being amortized ratably over ten years. Under the Merger Rate Plan, which began on January 31, 2002, the MRA regulatory asset and other stranded costs are being amortized unevenly over ten years, with larger amounts being amortized in the latter years. See Item 8. Financial Statements and Supplementary Data - Note B. Rate and Regulatory Issues and Contingencies - “Merger Rate Plan Stranded Costs” for a further discussion of the ratemaking treatment related to this regulatory asset.Depreciation and amortization expense decreased approximately $94 million for the year ended March 31, 2003 as compared to the year ended December 31, 2001, decreased approximately $28 million in the three months ended March 31, 2002 as compared to the same period in 2001, and decreased by $20 million in calendar year 2001 as compared to 2000, primarily as a result of the sale of the Company’s generation assets at various times during 1999 through 2001.Other taxes increased approximately $19 million for the year ended March 31, 2003 as compared to the year ended December 31, 2001, due to a decrease for the Gross Receipts Tax (“GRT”) Power for Jobs tax credit. In 2001, the Company amended prior years’ tax returns (1998 through 2000), thereby increasing the amount of Power for Jobs credit recorded in 2001. This increase was partially offset by a reduction in property taxes primarily resulting from the sale of the nuclear assets in November 2001.Other taxes increased $11 million in the three months ended March 31, 2002 as compared to the same period in 2001. In the first three months ended March 31, 2001, the Company received $22 million in GRT Power for Jobs credits due to a prior year true-up to actual filed returns. GRT credits of $1.2 million were received in the same period in 2002 due to a prior year true-up. This increase was partially offset by a reduction in the GRT tax rate of $6 million and a reduction in property taxes of $4 million primarily resulting from the sale of the nuclear assets in November 2001.Other taxes for the Company decreased in 2001 due to an increase in GRT credits ($40 million) received primarily due to an increase in the customers in the Company’s service territory that participate in New York State’s Power for Jobs program, a reduction in the GRT tax rate ($4 million) primarily as a result of the state tax law changes and a reduction in property taxes of $5 million primarily resulting from the sale of the nuclear assets in November 2001. The Company’s income taxes increased $84 million for the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001. The increase is due primarily from increased book taxable income for the twelve months ended March 31, 2003 and recording of previously deferred investment tax credits related to the sale of the nuclear assets of $80 million and the recording of the tax benefit of $43 million related to the non-cash write-off of $123 million of disallowed nuclear investment costs in 2001. Income taxes increased approximately $6 million in the three months ended March 31, 2002 primarily due to higher book taxable income. The 2001 increase in income taxes of approximately $16 million is primarily due to higher book taxable income. See Item 8. Financial Statements and Supplementary Data, - Note G. Federal, State and Foreign Income Taxes, for a reconciliation of the tax computed at the statutory rate.

~~ITEM~~The 5Company’s other income (deductions) decrease $74 million for the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001. This ~~MARKET~~is ~~FOR~~primarily ~~THE~~attributable ~~REGISTRANTS~~to the Company recording $80 million of previously deferred investment tax credits related to the sale of the nuclear assets in 2001.Other income (deductions) in the three months ended March 31, 2002 decreased $4 million primarily due to carrying charges on IPP buy out contract adjustments of $2 million and, in the three months ended March 31, 2001, other income reflected the recording of a non-cash incentive related to generation asset sales of $7 million for which there was no corresponding amount in the three months ended March 31, 2002. The Company’s ~~COMMON~~other ~~EQUITY~~income ~~AND~~(deductions) ~~RELATED~~increased ~~STOCKHOLDER~~$92 ~~MATTERS~~million in the year ended December 31, 2001 compared to the same period in 2000. This is primarily attributable to the Company recording $80 million of previously deferred investment tax credits related to the sale of the nuclear assets in 2001.The Company’s interest charges decreased $33 million in the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001, decreased $13 million in three months ended March 31, 2002 as compared to the three months ended March 31, 2001, and decreased $43 million in 2001 compared 2000, mainly due to the repayment and early repayment of debt during 1999 through March 31, 2003, and to a lesser extent, lower rates. Preferred dividends decreased $25 million in the twelve months ended March 31, 2003 from the twelve months ended December 31, 2001 due to preferred stock redemptions, decreased $0.1 million from the three months ended March 31, 2002 as compared to the same period in 2001 due to preferred stock redemptions, decreased $0.6 million from 2000 to 2001 due to sinking fund redemptions.

~~Holding~~EFFECTS ~~Company~~OF ~~Formation. On~~CHANGING March 18, 1999, Niagara Mohawk Power Corporation (“Niagara Mohawk”) was reorganized into a holding company structure in accordance with its Agreement and Plan of Exchange between Niagara Mohawk and Niagara Mohawk Holdings, Inc. (“Holdings”). Holdings was incorporated on April 2, 1998, as a wholly owned subsidiary of Niagara Mohawk. Niagara Mohawk’s outstanding common stock was exchanged on a share-for-share basis for Holdings’ common stock. Niagara Mohawk’s preferred stock and debt were not exchanged as part of the share exchange and continue as obligations of Niagara Mohawk. Upon the share exchange on March 18, 1999, shares originally issued to Niagara Mohawk were cancelled. On January 31, 2002, the merger of Holdings and National Grid was completed. Niagara Mohawk will maintain its existing name and will remain an indirect wholly owned subsidiary of National Grid. See Item 8. Financial Statements and Supplementary Data, - (Unaudited). Subsequent Event – Merger with National Grid for further discussion of the merger. PRICES

The Company is especially sensitive to inflation because of the amount ~~Niagara~~of ~~Mohawk~~capital ~~Common~~it ~~Stock. Niagara~~typically ~~Mohawk~~needs isand ~~authorized~~because toits ~~issue~~prices ~~250~~are ~~million~~regulated ~~shares~~using a rate-base methodology that reflects the historical cost of ~~common~~utility ~~stock~~plant.The ~~with~~Company’s aconsolidated ~~par~~financial ~~value~~statements are based on historical events and transactions when the purchasing power of $1the dollar was substantially different than now.~~00.~~ The Aseffects of ~~December~~inflation 31on most utilities, including ~~2001~~the Company, ~~Niagara~~are ~~Mohawk~~most ~~has~~significant in the areas of depreciation and ~~187,364,863~~utility ~~shares~~plant. The ~~outstanding,~~Company could not replace its utility assets for the historical cost value at which they are ~~all~~recorded ~~held~~on byits ~~Holdings~~books. In addition, the Company would not replace these with identical assets due to technological advances and ~~are~~competitive and regulatory changes that have occurred. In light of these considerations, the depreciation charges in operating expenses do not ~~traded~~reflect the cost of providing service if new facilities were installed. See “Long Term” below for a discussion of the Company’s future capital requirements.

~~The~~LIQUIDITY ~~indenture~~AND ~~securing Niagara~~CAPITAL Mohawk’s mortgage debt provides that retained earnings shall be reserved and held unavailable for the payment of dividends on common stock to the extent that expenditures for maintenance and repairs plus provisions for depreciation do not exceed 2.25 percent of depreciable property as defined therein. Such provisions have never resulted in a restriction of Niagara Mohawk’s retained earnings. RESOURCES

Short Term. At March 31, 2003, the Company’s principal ~~Niagara~~sources ~~Mohawk~~of ~~Preferred~~liquidity ~~Stock~~included cash and cash equivalents of $34 million and accounts receivable of $543 million. The ~~share~~Company ~~exchange~~has ~~and~~a ~~the~~negative ~~formation~~working capital balance of ~~the~~$659 ~~holding~~million ~~company~~primarily ~~structure~~due to long-term debt due within one year of ~~did~~$612 ~~not,~~million and ~~the~~short-term ~~merger~~debt of $198 million. Ordinarily, construction related short-term borrowings are refunded with ~~National~~long-term ~~Grid~~securities ~~does~~on ~~not,~~a periodic ~~change~~basis. This approach generally results in a working capital deficit. Working capital deficits may also be a result of the ~~rights~~seasonal nature of the ~~holders~~Company’s operations as well as the timing of differences between the collection ~~outstanding~~of ~~shares~~customer receivables and the payments of ~~Niagara~~fuel ~~Mohawk’s~~and ~~preferred~~purchased ~~stock.~~power ~~Niagara~~costs. As ~~Mohawk’s~~discussed ~~preferred~~below, ~~stock~~the ~~continues~~Company tobelieves ~~rank~~it ~~senior~~has sufficient cash flow and borrowing capacity to ~~Niagara~~fund such deficits as necessary in the near term. ~~Mohawk~~The Company’s ~~common~~outstanding ~~stock~~short-term ~~(all~~debt of ~~which~~$198 ismillion ~~held~~consists of byborrowings ~~Holdings~~from ~~and~~other ~~indirectly by~~ National Grid) asUSA tocompanies ~~dividends~~through ~~and~~the asmoney topool. For ~~distribution~~a further discussion of ~~Niagara~~the ~~Mohawk’s~~money pool, see Item 8. Financial Statements and ~~assets~~Supplementary ~~upon~~Data ~~any~~- ~~liquidation~~Note F – Bank Credit Arrangements.Net cash from operating activities was $599 million for the Company for twelve months ended March 31, 2003 which funded its acquisition of utility plant and the retirement of certain debt obligations.

OnThe ~~December~~Company’s ~~21,~~long-term ~~2001, National~~debt ~~Grid~~due ~~announced that it will,~~ within aone year ofis ~~closing the acquisition~~$612 ofmillion ~~Holdings~~at ~~(which~~March ~~occurred on January~~ 31, ~~2002)~~2003. In addition, ~~have~~construction ~~Niagara~~expenditures ~~Mohawk~~planned within orone ~~an affiliate~~year ~~make~~are ~~offers~~estimated to ~~purchase~~be ~~all~~$297 ~~of the then outstanding preferred stock of Niagara Mohawk~~million. These ~~Such~~capital ~~offers will be made at prices that~~ requirements are ~~customary~~planned ~~for a tender offer~~ to ~~purchase similar preferred stock and will~~ be ~~determined~~financed atprimarily ~~the time~~from ~~the~~internally ~~offers~~generated ~~are~~funds ~~made. Such determination of prices will be made by National~~and ~~Grid~~borrowings ~~based~~from onother ~~advice of an investment banking firm.~~ National Grid~~’s commitment~~ ~~will~~USA ~~not~~companies ~~affect~~through the ~~ability~~Money ofPool ~~Niagara Mohawk to voluntarily redeem~~ or ~~otherwise call its preferred stock. The making of such offers in the future~~ ~~will also be subject to receiving all regulatory approvals required for preferred stock offerings~~directly.

The Company’s net cash used in investing activities increased On$66 ~~February~~million 5for the twelve months ended March 31, ~~2002~~2003 compared to the twelve months ended December 31, ~~Niagara~~2001. This ~~Mohawk~~increase ~~announced~~was ~~that~~primarily itas ~~will~~a ~~redeem~~result ~~all~~of ~~remaining~~more proceeds ~~outstanding~~being ~~shares~~received in the twelve months ended twelve months ended December 31, 2001 from such generation sales than in the twelve months ended March 31, 2003 by $104 million. This was partially offset by an increase in cash provided by other investments of $35 million.The Company’s net cash used in financing activities decreased $8 million for the ~~following~~twelve ~~series~~months ended March 31, 2003 as compared to the twelve months ended December 31, 2001, primarily due to a decrease in the redemption of long-term debt, offset by an ~~preferred~~increase ~~stock:~~in common dividends to Holdings.Long Term. The Company’s total capital requirements consist of amounts for its construction program, working capital needs, and maturing debt issues. Construction expenditure levels for the energy delivery business are generally consistent from year-to-year. The following table summarizes long-term contractual cash obligations of the Company:

6.10% Series ($100 par value), at the redemption price of $101.00 per share; 7.45% Series ($100 par value), at the redemption price of $100.73 per share; 7.72% Series ($100 par value), at the redemption price of $102.36 per share; Adjustable Rate Series A ($25 par value), at the redemption price of $25 per share; Adjustable Rate Series B ($25 par value), at the redemption price of $25 per share; Adjustable Rate Series C ($25 par value), at the redemption price of $25 per share.


			Payment due in:
			Less than	1 - 3	4 - 5	After 5
($'s in Millions)			1 year	years	years	years	Total

Long-term Debt			$ 612	$ 1,073	$ 479	$ 2,401	$ 4,565
Electric purchase power commitments			619	1,020	861	1,869	4,369
Gas supply commitments			193	213	75	22	503
Derrivative swap commitments*			192	299	274	29	794
Construction expenditures**			297	N/A	N/A	N/A	297
	Total contractual cash obligations		$ 1,913	$ 2,605	$ 1,689	$ 4,321	$ 10,528

	*	- 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 not considered contractual obligations
		and are therefore not included.

In connection with an audit performed by PSC Staff, the Company reached a ~~These~~settlement ~~preferred~~with ~~stock~~the Staff that resolves all issues associated with its pension ~~series~~and ~~have~~other ~~been~~postretirement ~~called~~benefit obligations for ~~redemption~~the onperiod prior to the acquisition of the Company by National Grid. The settlement is subject to approval by the full New York State Public Service Commission. Among other things, the settlement covers the funding of the Company’s pension and post-retirement benefit plans. Under the settlement, the Company agreed to provide $100 million of tax-deductible funding by April 30, 2003 (which it funded in March 42003), ~~2002~~and an additional $209 million, on a tax-deductible basis, by December 31, 2011. The Company will earn a rate of return of at least 6.60 percent on any portion of the ~~above~~$209 ~~indicated~~million that it funds before December ~~redemption~~31, ~~prices~~2011, ~~together~~plus 80 percent of the amount by which the rate of return on the pension and post-retirement benefit funds exceeds 5.34 percent. This settlement resolves all PSC Staff audit issues related to the pre-acquisition period with the ~~accrued~~exception of certain gas deferrals and ~~unpaid~~a ~~dividends~~Staff ~~through~~review ~~March~~of 4a pending Company compliance filing related to the sale of the Nine Mile Nuclear Station.See Item 8. Financial Statements and Supplementary Data - Note I. Commitments and Contingencies, for a detailed discussion of the electric ~~2002~~purchase power commitments and the gas supply, storage and pipeline commitments and Note J. Derivatives and Hedging Activities for a detailed discussion of IPP and fossil/hydro swaps and Note E. Long-term Debt for a detailed discussion of mandatory debt repayments.

~~Whenever~~Capital ~~dividends~~requirements ~~on Niagara Mohawk’s preferred stock~~ are inplanned ~~default in an amount equivalent~~ to ~~four~~ ~~full~~be ~~quarterly~~financed ~~dividends~~primarily ~~and~~from ~~thereafter until all dividends thereon are~~internally ~~paid~~generated orfunds ~~declared~~ and ~~set~~borrowings ~~aside~~from ~~for~~other ~~payment,~~National ~~the~~Grid ~~holders~~USA ofcompanies ~~such preferred stock~~through ~~can elect a majority of~~ the ~~Board~~money ofpool ~~Directors~~or ~~of Niagara Mohawk~~directly. The ~~Whenever dividends~~Company onalso ~~any~~has ~~preference~~the ~~stock~~ability ~~are~~to inissue ~~default~~first mortgage inbonds ~~an amount equivalent~~ to ~~six full~~the ~~quarterly~~extent ~~dividends~~that ~~and~~there ~~thereafter~~have ~~until~~been ~~all~~maturities ~~dividends~~or ~~thereon~~early redemptions ~~are~~since ~~paid~~June ~~or declared~~30, ~~and~~1998. Through ~~set~~March ~~aside~~31, ~~for payment~~2003, the ~~holders~~Company ofhad ~~such stock can elect two~~$991 ~~members~~million toin ~~the~~such ~~Board~~first ofmortgage ~~Directors~~bond ofmaturities ~~Niagara~~and ~~Mohawk~~early redemptions. This ~~No dividends on preferred~~is ~~stock~~expected ~~are~~to ~~now~~increase into ~~arrears~~over ~~and~~$1,500 nomillion ~~preference~~in ~~stock~~2005 isbased ~~now~~on ~~outstanding.~~scheduled maturities.

~~Niagara~~On ~~Mohawk~~May ~~paid preferred~~1, ~~dividends~~2003, onthe ~~March~~Company ~~31,~~completed ~~June~~the ~~30,~~restructuring ~~September~~of ~~30,~~$414 ~~and~~million ~~December~~of variable ~~31,~~rate ~~2001~~tax exempt bonds. ~~Niagara~~ The ~~Mohawk~~bonds ~~estimates~~are ~~that~~currently ~~none~~in ofthe auction rate mode, which allowed the ~~2001~~Company ~~preferred~~to ~~stock~~terminate ~~dividends~~the ~~will constitute~~$424 amillion ~~return~~of letter of credit ~~capital,~~facilities ~~and~~that ~~therefore,~~were ~~all~~in ofplace ~~such~~to ~~dividends~~provide ~~are~~liquidity ~~subject~~support for principal toand ~~federal~~interest ~~tax~~while asthe ~~ordinary~~bonds ~~income~~were in a variable rate mode.

~~ITEM~~On 6May 1, 2003, the Company redeemed early $170 million of First Mortgage Bonds. In ~~SELECTED~~addition, ~~CONSOLIDATED~~on ~~FINANCIAL~~July ~~DATA~~7, 2003, the Company plans to redeem early approximately $487 million of Senior Notes. The funds provided for these redemptions have come from available cash within the National Grid USA Money Pool, a long term note issued to National Grid USA, and borrowings from National Grid Transco, parent company of National Grid USA.New Accounting Standards: In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (“FAS 143”). FAS 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. FAS 143 is effective for fiscal years beginning after June 15, 2002. The Company has evaluated the impact of this standard on its financial position and results of operations, and the Company does not believe it has any asset retirement obligations that would have a significant impact on its results of operations, cash flows, or financial position.In April 2003 the FASB issued SFAS No. 149 “Amendment of Statement 133 on Derivative Instruments and Hedging activities, an amendment of Statement 133” (“FAS 149”). FAS 149 amends and clarifies financial accounting and reporting for derivative instruments and is effective for contracts entered into after June 30, 2003. The Company does not expect the adoption of this statement to have a material effect on its financial position and results of operations.In May 2003 the FASB issued SFAS 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.

~~The~~ITEM following tables set forth selected financial information for Niagara Mohawk for each of the five years during the period ended December 31, 2001, which have been derived from the audited financial statements of Niagara Mohawk, and should be read in connection therewith7A. QUANTITATIVE AsAND ~~discussed~~QUALITATIVE inDISCLOSURES ~~Item~~ABOUT ~~7. Management’s Discussion and~~MARKET Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements, the following selected financial data for Niagara Mohawk is not likely to be indicative of Niagara Mohawk’s future financial condition, results of operations or cash flows. RISK

~~2001 2000* 1999* 1998 1997~~The Company is exposed to various market risks because of transactions ~~-----------------------------------------------------------------------------------------------------------~~conducted in the normal course of business. The financial instruments held or ~~Operations~~issued by the Company are used for investing, financing, hedging or cost control and not for trading.Quantitative and qualitative disclosures are discussed by market risk exposure category: Interest Rate RiskCommodity Price RiskEquity Price RiskAn Exposure Management Committee (~~000's~~“EMC”) was set up to monitor and control efforts to ~~Operating~~manage ~~revenues $4,123,391 $3,865,949 $3,827,340~~these risks. $The ~~3,826,373 $3,966,404~~EMC issues and oversees the Financial Risk Management ~~Income~~Policy (~~loss~~the “Policy”) ~~from~~that ~~continuing~~outlines ~~operations~~the parameters within which corporate ~~before~~managers ~~extraordinary~~are ~~item 29~~to engage in,~~521 (21~~ manage,~~403) 21,746 (120,825) 183,335~~ and report on various areas of risk ~~Net~~exposure. At ~~income~~the ~~(loss) 29~~core of the Policy is a condition that the Company will engage in activities at risk only to the extent that those activities fall within commodities and financial markets to which it has a physical market exposure in terms and in volumes consistent with its core business of delivering electricity and natural gas. The policies of the Company may be revised as its primary markets continue to change,~~521 (22,312) (2,061) (120,825) 183,335~~ principally as increased competition is introduced and the role of the Company in these markets evolves.Interest Rate Risk. The Company maintains long-term debt at fixed interest rates and other long-term debt and intercompany short-~~--------------------------------------------------------------------------------------------------------~~term debt at variable rates. A ~~Common~~controlling ~~stock~~factor ~~data:~~on the exposure to interest rate variations is the mix of ~~Book~~fixed ~~value~~to ~~per~~variable ~~share~~rate atinstruments ~~year~~maintained end ** ** **by Niagara Mohawk. ~~$ 16~~For March 31, 2003 and 2002, adjustable rate instruments comprise 8.~~92 $ 18~~8 percent and 10.895 percent ~~Market~~of ~~price~~total capitalization. atFor ~~year~~the ~~end ** ** ** 16~~same periods, adjustable rate promissory notes are 9.1/ percent and 8 10.8 ~~1/2 Ratio~~percent of ~~market~~total ~~price~~long-term debt. The proportion of adjustable instruments to total capitalization decreased because of the reduction ~~book~~in ~~value~~borrowings from the money pool. In the aggregate at March 31, 2003 and 2002 variable rate instruments do not constitute a significant portion of total capitalization and debt thus, limiting Niagara Mohawk’s exposure to interest rate fluctuations.If interest rates increased 1 percent next fiscal year, ~~end ** ** ** 95~~Niagara Mohawk’s interest expense would increase by approximately $6.~~3% 55~~1 million.~~6% Income~~ This ~~(loss)~~figure ~~from~~was ~~continuing~~derived ~~operations~~by applying a hypothetical 1 ~~per~~percent ~~average~~variance ~~common~~to ~~share ** ** ** (~~the variable rate debt of $0413.~~95)~~ 8 million plus the short-term variable borrowings of $1198 million at March 31, 2003.01 The ~~Basic~~interest rates on short term borrowings are tied to the published, 30 day, commercial paper rate with the interest rate associated with the amount borrowed from National Grid adjusted monthly. Commodity Price Risk. The Company is exposed to commodity market price fluctuations in two basic areas: (1) the cost of electricity and ~~diluted~~natural ~~earnings~~gas for resale to its customers, and (~~loss~~2) the ~~per~~impact that natural gas, electricity and oil prices have on the swap contracts ~~average~~and ~~common~~one ~~share ** ** ** ($0~~large non-MRA IPP contract.~~95) $1~~ For both gas and electricity, the Company reconciles and recovers commodity costs currently in rates to its customers who purchase the commodity.01The Company takes positions in ~~Rate~~order to mitigate expected price volatility but only to the extent that quantities are based on expectations of ~~return~~delivery. The Company attempts to mitigate its customers’ exposure to price volatility through a program that hedges risks as appropriate. The Company does not speculate on ~~common~~movements in ~~equity ** ** ** (5~~the underlying prices for these commodities.~~3)% 5~~ Commodity purchases are based on analyses performed in relation to expected customer deliveries for electricity and natural gas.5% The volume of commodities covered by hedging ~~Dividends~~contracts ~~paid~~does ~~per~~not ~~common~~exceed ~~share ** ** ** - -~~amounts needed for customer consumption in the normal ~~-----------------------------------------------------------------------------------------------------------~~course of business or to offset adverse price movements in the contracts being ~~Capitalization:~~hedged.As ~~(000's)~~part of the 1998 MRA, the Company entered into restated ~~Common~~indexed ~~equity $2~~swap contracts with eight IPPs. The company also entered into financial swap agreements associated with the sales of the Huntley,~~386~~ Dunkirk,~~998 $2~~ and Albany generating stations. The costs of these contracts are fully recovered from customers under the Company’s rate plan. See Item 8. Financial Statements and Supplementary Data - Note J. Derivatives and Hedging Activity,~~434,223~~ for a more detailed discussion of these swap contracts. The fair value of the liability under the swap contracts is based upon the difference between projected future market prices and projected contract prices applied to the notional quantities and discounted to the present value. This liability was approximately $2793.0,~~785,171~~ and $653.9 3at March 31,~~170~~ 2003 and 2002,~~142 $2,727,527~~ respectively and is ~~Non~~recorded on the Company’s balance sheets as a “Liability for swap contracts.” The increase is primarily due to a lowering of the discount rate plus a revaluation of the contracts indicating higher forecasted contract prices. These increases were somewhat offset by normal contract settlements. The discount rate is a market-~~redeemable~~based ~~preferred~~rate ~~stock 440~~representing the yield curve through the life of the contracts. Based upon the PSC’s approval of the restated contracts,~~000 440~~ including the indexed swap contracts,~~000 440~~ as part of the MRA and being provided a reasonable opportunity to recover the estimated indexed swap liability from customers,~~000 440,000 440,000~~ the Company has recorded a corresponding regulatory ~~Mandatorily~~asset. The ~~redeemable~~amounts of the recorded liability and regulatory asset are sensitive to ~~preferred~~changes ~~stock 50~~in anticipated future market prices and changes in the indices upon which the indexed swap contract payments are based. If the indexed contract price were to increase or decrease by 1 percent,~~700 53,750 61,370 68,990 76,610~~ the Company would see ~~Long-term~~a ~~debt~~ $16.4~~,419,822 4,678,963 5,042,588 6,417,225 3,417,381~~ million increase or decrease in the present value of the projected over-~~----------------------------------------------------------------------------------------------------------~~market exposure. If the market prices were to increase or fall by 1 7percent,~~297,520~~ the Company would see a $7~~,606,936 8,329,129 10,096,357 6,661,518~~.7 million decrease or increase in the ~~Long~~projected over-~~term~~market ~~debt~~exposure. If ~~maturing~~the ~~within~~discount rate were one ~~year 546~~half percent higher or lower,~~858 628,325 613,740 312,240 67,095~~ the net present value of the projected over market exposure would decrease or increase by approximately $9.7 million.The area of exposure to cash flow is in the indexing of the contract prices for the IPP indexed swaps and the Albany swap (Huntley and Dunkirk have fixed contract prices) and a non-MRA IPP where payments are based on gas prices. The contract payments under the IPP and Albany swaps and the non-~~---------------------------------------------------------------------------------------------------------~~MRA IPP are indexed to the ~~Total $7~~costs of fuel,~~844~~ primarily natural gas; Albany can be oil or gas. As fuel costs rise,~~378 $8~~ the payments the Company pays under those contracts increase. The current rate plan allows the pass-through of the commodity cost of power to customers; however,~~235~~ the Company uses certain financial instruments to limit the impact of commodity fluctuations on these payments. The Company has taken steps to mitigate the potential impact that fuel prices would have on the payments for the IPP and Albany swaps,~~261 $8,942,869~~ and a physical power contract with a non-MRA IPP. ~~$10~~To limit this exposure,~~408,597 $6,728,613~~ the Company purchased NYMEX gas futures contracts and entered into fixed-for-floating swaps on gas basis costs. To hedge the non-~~--------------------------------------------------------------------------------------------------------~~MRA ~~Capitalization~~IPP ~~ratios:~~contract, ~~(including~~the ~~long~~Company purchased NYMEX gas futures. See Item 8. Financial Statements and Supplementary Data -~~term~~ ~~debt~~Note ~~maturing~~J. ~~within~~Derivatives ~~one~~and ~~year)~~Hedging Activity for ~~Common~~a ~~stock~~more ~~equity 30~~detailed discussion of these contracts.~~4% 29~~ Even with the regulatory recovery of the cost of these contracts, the Company believes it is prudent to hedge these payments.6% For the period ended March 31, 2003, gas futures were purchased to hedge approximately 100 percent of the amount needed to offset gas price changes.~~1% 30.5% 40.5%~~At March 31, 2002, the Company did not have any open NYMEX ~~Preferred~~futures ~~stock 6~~or basis swaps for this purpose.~~3% 6.0% 5.6% 4.9% 7.7%~~ At March 31, 2003, the open NYMEX ~~Long-term~~futures ~~debt 63~~the Company had in place to hedge the payments under these contracts had a fair value gain of $14.~~3% 64~~2 million.~~4% 63.3% 64.6% 51.8%~~Activity for the fair value of the NYMEX futures and gas basis swaps for the 12 months ended March 31, 2003, is as follows:

* Amounts include extraordinary item for the early extinguishment of debt, see Item 8. Financial Statements and Supplementary Data - Note 4. Capitalization. ** All of Niagara Mohawk’s shares of common stock are owned by its parent company, therefore, per share data is not relevant.

(in thousands of dths and dollars)	*Hedges of IPP Swaps*				*Hedges Non-MRA IPP*
	NYMEX Futures		Gas Basis Swaps		NYMEX Futures
	Dth	Fair Value	Dth	Fair Value	Dth	Fair Value
March 31, 2002 Asset / (Liability)	-	-	-	-	-	-
New Contracts	58,200.0	-	3,264.3		4,900.0
Settled during period	(37,300.0)	$ (29,732.3)	(3,264.3)	$ (218.5)	(3,200.0)	$ (2,673.0)
Mark-to-market Adjustments	-	42,889.7	-	218.5	-	3,742.7
March 31, 2003 Asset / (Liability)	20,900.0	$ 13,157.4	-	$ -	1,700.0	$ 1,069.7

~~2001 2000* 1999* 1998 1997 ---------------------------------------------------------------------------------------------------------- Financial~~Gas ~~ratios~~Supply Price Risk: The cost of natural gas sold ~~EBITDA,~~to ascustomers ~~defined~~fluctuates ~~(000's)*** $~~during ~~1,181,660 $~~the ~~1,130,100 $~~year ~~1,267,500 $ 965,300 $ 909,200 Net~~with ~~cash~~prices ~~interest,~~historically asmost ~~defined~~volatile in (000's)***the winter months. ~~$ 321,285 $ 363,600 $ 404,700 $ 343,600 $ 218,900 Ratio~~The ofCompany’s ~~EBITDA~~gas torate ~~net~~agreement ~~cash~~includes ~~interest 3.7 3.1 3.1 2.8 4.2~~a ~~Ratio~~provision for the collection or pass back of ~~earnings~~increases toor ~~fixed~~decreases ~~charges 0.90 0.93 1.01 0.57 2.02~~in purchased ~~Ratio~~gas costs. The PSC has also issued a Statement of ~~earnings~~Policy tothat ~~fixed~~the ~~charges~~Company ~~and~~attempt ~~preferred~~to ~~stock~~reduce ~~dividends 0.84 0.87 0.94 0.52 1.67 Other~~the ~~ratios~~price (%volatility ofin ~~operating~~the ~~revenues):~~gas commodity portion of customers’ ~~Fuel~~bills. To implement this policy, ~~electricity~~the ~~purchased~~Company uses futures, options, and swaps to hedge against gas ~~purchased 42~~price fluctuations.~~7% 41.2% 33.0% 39.6% 44.4%~~ The hedging program will ~~Other~~be ~~operation~~consistent ~~and~~with ~~maintenance expenses 23.2 22.8 23.8 24.8 21.1~~ the ~~Depreciation~~Financial ~~and~~Risk ~~amortization 7~~Management Policy.~~1 8.0 9.0 9.3 8.6~~During the reporting ~~Amortization/accretion~~period, the Company attempted to hedge approximately 50 percent of its ~~MRA/IPP~~forecasted ~~buyout~~annual ~~costs 8.8 9.6 9.5 3.1~~ demand for gas through a program using in-ground storage and financial ~~Amortization~~instruments. The ofhedging ~~nuclear~~program ~~regulatory~~was further refined to skew the ~~assets 0.7 - - - -~~ hedging ~~Disallowed~~program ~~nuclear~~more ~~investment~~heavily ~~costs 3~~toward the winter season (November through March).~~0 - - - -~~ The ~~Income~~Company uses a combination of NYMEX gas futures and ~~other~~a ~~taxes 3~~program of combination call and put options.~~9 7.0 11.3~~ Each NYMEX futures or option contract represents 10~~.3 15.1~~,000 Dth ~~Operating~~of ~~income 8~~gas.~~9 11.1 13.9 4.4 14.1~~ At ~~Balance~~March ~~available~~31, 2003 the net open position of cash flow hedges for ~~common~~gas supply ~~stock ** ** ** (4.~~was a gain of $1) .3 million.~~7 ---------------------------------------------------------------------------------------------------------- Miscellaneous:~~ There ~~(000's) Gross~~were ~~additions~~no toopen ~~utility~~futures ~~plant $ 253,252 $ 273,830 $ 298,081 $ 392,200 $ 290,757~~contracts or ~~Total~~options ~~utility~~at ~~plant 6~~March 31,~~811,968 9,801,622 9,792,291 11,431,447 11,075,874 Accumulated~~ ~~depreciation~~ 2002. The ~~and~~following ~~amortization 2,194,273 4,019,282 3,904,049 4,553,448 4,207,830 Regulatory~~table ~~Assets 5,826,765 5,316,007 5,517,786 5,468,229 1,176,824~~details the fair value ~~Total~~activity ~~Assets 11,485,526~~ for gas cash flow hedges for the 12 months ended March 31,~~307,238 12,445,608 13,861,187 9,584,141~~ ~~----------------------------------------------------------------------------------------------------------~~ 2003:

* Amounts include extraordinary item for the early extinguishment of debt, see Item 8. Financial Statements and Supplementary Data - Note 4. Capitalization ** All of Niagara Mohawk’s shares of common stock are owned by its parent company, therefore, per share data is not relevant. *** See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Financial Position, Liquidity and Capital Resources - Financial Position” for a discussion of EBITDA and a reconciliation of net income to EBITDA.

(in thousands of dths and dollars)	*Hedges of Gas Supply*
	NYMEX Futures		Call Options		Put Options
	Dth	Fair Value	Dth	Fair Value	Dth	Fair Value
March 31, 2002 Asset / (Liability)	-	-	-	-	-	-
New Contracts	10,790.0		12,820.0	$ 2,757.8	12,770.0	$ (2,752.6)
Settled during the period	(9,000.0)	$ (10,038.6)	(9,130.0)	-	(9,080.0)	-
Mark-to-market Adjustments		10,894.6		(1,486.5)		1,886.3
March 31, 2003 Asset / (Liability)	1,790.0	$ 856.0	3,690.0	$ 1,271.3	3,690.0	$ (866.3)

~~NIAGARA~~The ~~MOHAWK~~above ~~POWER~~activity ~~CORPORATION~~coupled ~~AND~~with ~~SUBSIDIARY~~the ~~COMPANIES~~in-ground storage hedged approximately 50 percent of the Company’s gas needs for the year. The rest of the gas needs are met through market-based purchases that are subject to price fluctuations. All prudently incurred gas supply costs are mitigated by regulatory rate recovery.The extent to which market price movement would affect the value of the hedges would be matched by an offsetting change in the anticipated gas purchased costs for the quantity of gas hedged. Therefore, for the quantities hedged, variations in market costs would not result in any significant impact on earnings.Electricity Price Risk: The Company meets the majority of its electric requirements through a series of long-term physical and financial contracts. There are occasions when the Company may project a short position for electricity needed to supply customers. During those periods electricity is purchased at market prices. If certain proscribed risk values are exceeded during a time when the company forecasts a short power situation, the Company may use electric swaps to lock in a price for electricity. The Company did not use electric swaps during the year ended March 31, 2003. In April 2003, the Company began utilizing NYMEX electric swap contracts to hedge electric purchases for the summer 2003. The Company continues to evaluate the use of hedging instruments to manage the cost of electricity purchased.Equity Price Risk. With the sale of the nuclear generating stations on November 7, 2001 and the associated transfer of all decommissioning trust fund assets to the new owners, the Company eliminated its equity price risk in decommissioning funds.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

InReports ~~recent years, federal and state regulatory initiatives have sought to provide separation~~ of ~~the vertically~~Independent integrated energy generation, transmission and distribution functions and promote competition and lower prices. This unbundling of services has led to some restructuring throughout the industry. Niagara Mohawk’s response to these developments was to formulate a restructuring strategy and a multi-year rate plan which provided for its exit of the generation business, reduction in the amount of its future over-market purchase power obligations, recovery of its stranded costs and lower prices to customers. Implementation of the restructuring strategy commenced in 1998 with the regulatory approval of the Power Choice rate plan and the consummation of the MRA, and 1999 through 2001 were years punctuated by the further execution of the restructuring strategy. Auditors

~~The~~Consolidated ~~year~~Statements ~~2000~~of ~~was~~Operations, aConsolidated ~~year~~Statements inof Retained ~~which~~Earnings, ~~the~~and ~~companies~~Consolidated ~~experienced~~Statements ~~even~~of ~~more~~Comprehensive ~~significant~~Income ~~changes,~~(Loss) ~~since~~for ~~Holdings~~the ~~entered~~year ~~into~~ended aMarch ~~merger~~31, ~~agreement with National Grid~~2003, ~~whereby~~the ~~Niagara~~60 ~~Mohawk~~day ~~has become~~period anended ~~indirect~~March ~~wholly-owned~~31, ~~subsidiary~~2002, ofthe ~~National~~30 ~~Grid,~~day period ~~effective~~ended January 31 ~~2002.~~30, ~~In 2001 and~~ 2002, ~~major~~and ~~accomplishments~~for ~~were made in~~ the ~~implementation of~~years ~~the~~ended ~~restructuring~~December ~~strategy.~~31, ~~The key events in~~ 2001 and ~~2002 were:~~ 2000.

•Consolidated OnBalance ~~January~~Sheets ~~19,~~at ~~2001~~March 31, ~~Holdings’~~2003 ~~shareholders approved the merger.~~and 2002

•Consolidated OnStatements ~~January~~of 29Cash Flows for the year ended March 31, ~~2001~~2003, ~~National~~the 60 ~~Grid~~day ~~shareholders~~period ~~approved~~ended March 31, 2002, the ~~merger~~30 day period ended January 30, 2002, and the years ended December 31, 2001 and 2000.

•Notes Onto ~~January~~Consolidated ~~30,~~Financial ~~2001, Niagara Mohawk sold its share of the Roseton power plant.~~Statements

• REPORT OnOF INDEPENDENT ~~August 29, 2001, the PSC approved rate plan changes to cover the final two years of the Power Choice agreement. The Merger Rate Plan superceded this filing.~~AUDITORS

•To Onthe ~~November~~Stockholders 7and Board of Directors ofNiagara Mohawk Power Corporation:In our opinion, ~~2001~~the accompanying consolidated balance sheets and the related consolidated statements of operations and retained earnings, of comprehensive income (loss) and of cash flows present fairly, in all material respects, the financial position of Niagara Mohawk ~~sold~~Power Corporation ~~Nine~~and ~~Mile~~its ~~Point~~subsidiaries ~~Unit~~at 1March 31, 2003 and ~~its~~2002, ~~share~~and the results of their ~~Unit~~operations 2and their cash flows for the year ended March 31, 2003 and the sixty day period ended March 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to aexpress ~~subsidiary~~an opinion on these financial statements based on our audits. We conducted our audits of ~~Constellation~~these ~~Energy~~statements ~~Group~~in accordance with auditing standards generally accepted in the United States of America, ~~Inc~~which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An ~~(“Constellation”)~~audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion./s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLPBoston, MassachusettsMay 7, 2003, except for the Legal Matters section of Note I, as to which the date is May 30, 2003

•REPORT OnOF ~~November~~INDEPENDENT ~~28, 2001, the PSC approved Niagara Mohawk’s ten-year Merger Rate Plan.~~AUDITORS

•To Onthe Stockholders and Board of Directors ofNiagara Mohawk Power Corporation:In our opinion, the accompanying consolidated statements of operations and retained earnings, of comprehensive income (loss) and of cash flows present fairly, in all material respects, the results of operations and cash flows of Niagara Mohawk Power Corporation and its subsidiaries for the thirty day period ended January 1630, 2002 and for each of the two years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the ~~SEC~~United ~~approved~~States of America. These financial statements are the ~~merger~~responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion./s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLPBoston, MassachusettsMay 14, 2002

• On January 31, 2002, the merger was consummated.

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Statements of Operations
(In thousands of dollars)
	For the Year	60 Day Period	30 Day Period	Three Months	For the Year Ended
	Ended March 31,	Ended March	Ended January	Ended March	December 31,
	2003	31, 2002	30, 2002	31, 2001	2001	2000
	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)	(Predecessor)
				(Unaudited)
Operating revenues:
Electric	$ 3,310,837	$ 539,758	$ 282,931	$ 823,566	$ 3,393,212	$ 3,207,447
Gas	708,613	149,947	79,691	356,140	721,501	658,502
	4,019,450	689,705	362,622	1,179,706	4,114,713	3,865,949
Operating expenses:
Electricity purchased	1,594,221	231,721	111,444	291,053	1,304,242	1,144,117
Fuel for electric generation	-	-	-	14,317	37,162	74,340
Gas purchased	393,796	83,477	46,651	249,760	419,324	357,524
Other operation and maintenance	840,367	158,367	116,485	248,196	952,853	888,387
Disallowed nuclear investment costs (Note A)	-	-	-	-	123,000	-
Amortization of stranded costs	149,415	23,533	40,911	91,073	393,136	375,487
Depreciation and amortization	198,253	32,877	16,671	77,768	292,224	311,803
Other taxes	253,207	40,892	20,298	50,403	234,346	283,511
Income taxes	93,277	26,362	4,036	24,368	9,582	(6,201)
	3,522,536	597,229	356,496	1,046,938	3,765,869	3,428,968
Operating income	496,914	92,476	6,126	132,768	348,844	436,981
Other income (deductions)	(1,340)	777	2,349	6,631	72,896	(18,785)
Income before interest charges	495,574	93,253	8,475	139,399	421,740	418,196
Interest:
Interest on long-term debt	318,149	56,567	28,490	97,203	367,291	407,288
Other interest	51,554	6,040	926	8,186	35,091	38,554
	369,703	62,607	29,416	105,389	402,382	445,842
Net income (loss)	$ 125,871	$ 30,646	$ (20,941)	$ 34,010	$ 19,358	$ (27,646)

Consolidated Statements of Retained Earnings
(In thousands of dollars)
	For the Year	60 Day Period	30 Day Period	Three Months	For the Year Ended
	Ended March 31,	Ended March	Ended January	Ended March	December 31,
	2003	31, 2002	30, 2002	31, 2001	2001	2000
	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)	(Predecessor)
				(Unaudited)
Retained earnings at beginning of period	$ 29,317	$ 138,492	$ 167,044	$ 215,696	$ 215,696	$ 320,911
Net income (loss)	125,871	30,646	(20,941)	34,010	19,358	(27,646)
Purchase accounting adjustment	-	(138,492)	-	-	-	-
Call premium on preferred stock	-	(1,329)	-	-	-	-
Dividends on preferred stock	(5,568)	-	(7,611)	(7,758)	(30,850)	(31,437)
Dividend to Niagara Mohawk Holdings, Inc.	(63,914)	-	-	-	(37,160)	(46,132)
Retained earnings at end of period	$ 85,706	$ 29,317	$ 138,492	$ 241,948	$ 167,044	$ 215,696

Consolidated Statements of Comprehensive Income (Loss)
(In thousands of dollars)
	For the Year	60 Day Period	30 Day Period	Three Months
	Ended March 31,	Ended March	Ended January	Ended March	For the year ended December 31,
	2003	31, 2002	30, 2002	31, 2001	2001	2000
	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)	(Predecessor)
				(Unaudited)
Net income(loss)	$ 125,871	$ 30,646	$ (20,941)	$ 34,010	$ 19,358	$ (27,646)
Other comprehensive income(loss):
Unrealized gains (losses) on securities (net of
taxes of $758, $(92), $59, $361, $612,
$343, respectively)	(710)	126	(81)	(671)	(857)	(657)
Hedging activity (net of taxes of $(452), $(1,976),
$(800), ($1,950), $3,790,$-, respectively)	600	2,674	1,084	3,621	(5,127)	-
Additional minimum pension liability	-	-	(23,081)	267	(4,202)	(1,649)
Other comprehensive income (loss)	(110)	2,800	(22,078)	3,217	(10,186)	(2,306)
Comprehensive income(loss)	$ 125,761	$ 33,446	$ (43,019)	$ 37,227	$ 9,172	$ (29,952)

~~MERGER~~The ~~WITH~~accompanying ~~NATIONAL~~notes ~~GRID~~are an integral part of these financial statements.

On January 31, 2002, the acquisition of Holdings by National Grid was completed for a value of approximately $3.0 billion in cash and American Depositary Shares. The acquisition is being accounted for by the purchase method, the application of which, including the recognition of goodwill, is being recognized on the books of Niagara Mohawk, the most significant subsidiary of Holdings. The merger transaction resulted in over $1 billion of goodwill, which will be subject to SFAS No. 142, “Goodwill and Other Intangible Assets.” SFAS No. 142 requires that ratable amortization of goodwill be replaced with periodic tests of the goodwill’s impairment. Separable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives. See “Merger Rate Plan” for a discussion of the anticipated future results on Niagara Mohawk and Item 8. Financial Statements and Supplementary Data, - Note 2. Subsequent Event – Merger with National Grid (Unaudited) for further discussion of the merger.

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
(In thousands of dollars)


					March 31,	March 31,
ASSETS					2003	2002
					(Successor)	(Successor)
Utility plant, at original cost:
	Electric plant				$ 5,091,435	$ 4,938,709
	Gas plant				1,402,215	1,352,258
	Common Plant				351,987	359,429
	Construction work-in-progress				143,949	180,667
			Total utility plant		6,989,586	6,831,063
	Less: Accumulated depreciation and amortization				2,342,757	2,226,493
			Net utility plant		4,646,829	4,604,570

Goodwill					1,225,742	1,230,763

Other property and investments					94,314	95,785

Current assets:
	Cash and cash equivalents				30,038	9,882
	Restricted cash				25,350	8,082
	Accounts receivable (less reserves of $100,200
		and $61,300, respectively, and includes
		receivables from associated companies of
		$227 and $1,129, respectively)			543,207	534,914
	Notes receivable				73	50,050
	Materials and supplies, at average cost:
		Gas storage			4,795	3,335
		Other			16,401	17,484
	Derivative instruments (Note A and J)				16,354	411
	Prepaid taxes				90,770	17,491
	Current deferred income taxes (Note G)				35,458	49,704
	Other				10,483	5,075
			Total current assets		772,929	696,428

Regulatory and other non-current assets:
	Regulatory assets (Note B):
		Merger rate plan stranded costs			3,213,657	3,300,885
		Swap contracts regulatory asset			793,028	653,949
		Regulatory tax asset			143,765	203,905
		Deferred environmental restoration costs			301,000	297,000
		Pension and postretirement benefit plans			713,779	540,786
		Loss on reacquired debt			48,255	40,132
		Other			242,290	189,959
			Total regulatory assets		5,455,774	5,226,616

	Long-term notes receivable				-	199,822
	Other assets				48,171	47,604
			Total regulatory and other non-current assets		5,503,945	5,474,042

				Total assets	$ 12,243,759	$ 12,101,588

~~REGULATORY~~The ~~AGREEMENTS~~accompanying ~~AND~~notes ~~THE~~are ~~RESTRUCTURING~~an OFintegral ~~THE~~part ~~REGULATED~~of ~~ELECTRIC~~these financial ~~UTILITY BUSINESS~~statements.

Merger Rate Plan. On November 28, 2001, the PSC approved the Merger Rate Plan. This rate plan became effective on January 31, 2002, the closing of the merger. Key terms of the plan are as follows:

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
(In thousands of dollars)


					March 31,	March 31,
CAPITALIZATION AND LIABILITIES					2003	2002
					(Successor)	(Successor)
Capitalization:
	Common stockholder's equity:
		Common stock ($1 par value)			$ 187,365	$ 187,365
			Authorized - 250,000,000 shares
			Issued and outstanding - 187,364,863 shares
		Additional paid-in capital			2,621,440	2,722,894
		Accumulated other comprehensive income			16	126
		Retained earnings			85,706	29,317
			Total common stockholder's equity		2,894,527	2,939,702

	Preferred equity (Note D):
		Cumulative preferred stock ($100 par value, optionally redeemable)			42,625	44,756
			Authorized - 3,400,000 shares
			Issued and outstanding - 426,248 and 447,555 shares, respectively
		Cumulative preferred stock ($25 par value, optionally redeemable)			55,655	55,655
			Authorized - 19,600,000 shares
			Issued and outstanding - 1,113,100 shares

	Long-term debt (Note E)				3,453,989	4,146,642
	Long-term debt to affiliates (Note E)				500,000	-

			Total capitalization		6,946,796	7,186,755

Current liabilities:
	Accounts payable (including payables to associated companies
		of $34,029 and $8,890, respectively)			375,767	239,677
	Customers' deposits				25,843	18,918
	Accrued interest				108,927	111,515
	Short-term debt to affiliates (Note F)				198,000	419,000
	Current portion of long-term debt (Note E)				611,652	544,647
	Other				111,904	96,099
		Total current liabilities			1,432,093	1,429,856

Other non-current liabilities:
	Accumulated deferred income taxes (Note G)				1,157,796	1,108,232
	Liability for swap contracts (Note A and J)				793,028	653,949
	Employee pension and other benefits (Note H)				884,204	745,393
	Other				728,842	680,403
		Total other non-current liabilities			3,563,870	3,187,977

Commitments and contingencies (Notes B and I):
	Liability for environmental remediation costs				301,000	297,000

				Total capitalization and liabilities	$ 12,243,759	$ 12,101,588

°The ~~Net~~accompanying ~~customer~~notes ~~savings~~are of about $1 billion over the next 10 years, compared with rates projected without the merger. This includes a $152 million reduction in delivery charges compared to rates approved in Niagara Mohawk’s current rate agreement, followed by stabilized delivery charges for 10 years, subject to limited adjustments. This equals an ~~expected~~integral reduction in Niagara Mohawk electricity delivery rates of more than eight percent, which results in a projected five percent decrease in overall electricity bills, including a projected commodity cost, which will continue to be borne by customers. ° Price-stabilized commodity service for residential and commercial customers for several years, giving those customers significant protection from severe fluctuations in the generation marketplace. ° Agreement to forgo the collection of an estimated $850 million in nuclear-related costs that otherwise would have been collected in rates. ° Ability to recover a return on the remaining MRA regulatory asset. ° Also, as part of ~~the~~these financial ~~agreement, Niagara Mohawk would expand its annual upstate New York economic development efforts by $12~~statements.5 million. ° The extension by 16 months of the existing multi-year gas rate settlement agreement, resulting in a freeze in natural gas delivery rates through December 2004. ° Extension of the Low Income Customer Assistance Program and introduction of a special low-income rate. ° Establishment of a Service Quality Assurance Program that calls for up to $24 million in annual penalties or more under certain conditions, if defined customer service goals are not achieved. ° The continuation of the stranded cost recovery provisions under Power Choice with slight modifications.

~~Although~~NIAGARA ~~rates~~MOHAWK ~~will~~POWER beCORPORATION ~~lower under the Merger Rate Plan, Niagara Mohawk believes cost savings from the merger~~AND ~~should~~SUBSIDIARY ~~enable~~COMPANIESNOTES itTO toCONSOLIDATED ~~improve its operating results.~~FINANCIAL STATEMENTS

NOTE A – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIESBasis of Presentation: Niagara Mohawk Power Corporation ~~Choice~~(the ~~Rate~~“Company”) ~~Reductions~~is subject to regulation by the New York State Public Service Commission (“PSC”) and ~~Retail~~the ~~Choice~~Federal Energy Regulatory Commission (“FERC”) with respect to its rates for service under a methodology that establishes prices based on the Company’s cost. The Company’s accounting policies conform to Generally Accepted Accounting Principles (“GAAP”), including the accounting principles for rate-regulated entities with respect to the Company’s transmission, distribution and gas operations (regulated business), and are in accordance with the accounting requirements and ratemaking practices of ~~Electricity~~the ~~Supplier~~regulatory authorities.The Company’s consolidated financial statements include its accounts as well as those of its wholly owned subsidiaries. Inter-company balances and transactions have been eliminated.The ~~PSC~~closing of ~~approved~~the merger with National Grid USA (“National Grid”) and the ~~Niagara~~related ~~Mohawk~~push down and allocation of the purchase price has had a significant effect on the reported results of the Company. The sale of the Company’s generation ~~Power~~assets ~~Choice~~at ~~agreement~~various ontimes ~~March~~during 201999 through 2001 has also affected the comparability of the financial statements. The consolidated statements of cash flows for the Company have been presented to reflect the closings of the sales of the generation assets, ~~1998~~such ~~and~~that certain individual line items are net of the ~~rate~~effects ~~plan~~of the sales.Acquisition by National Grid: On January 31, 2002, the Company was ~~implemented~~acquired by National Grid for approximately $3 billion in cash and American Depository Shares in a purchase business combination recorded under the “push-down” method of accounting, resulting in a new basis of accounting for the “successor” period beginning ~~September~~January 131, ~~1998~~2002. Information ~~The~~relating to ~~Power~~all ~~Choice~~“predecessor” ~~agreement~~periods ~~outlined~~prior to the acquisition is presented ~~Niagara~~using the Company’s historical basis of accounting. The Company maintains its name and legal existence and remains a wholly owned subsidiary of Niagara Mohawk Holdings Inc. (“Holdings”) and, indirectly, National Grid.Change of Fiscal Year: The Company changed its fiscal year from a calendar year ending December 31 to a fiscal year ending March 31. The Company made this change in order to align its fiscal year with that of National Grid. The Company’s ~~future~~first ~~structure~~new full fiscal year began on April 1, 2002 and ended on March 31, 2003.Goodwill: The acquisition of the Company was accounted for by the purchase method, the application of which, including the recognition of goodwill, is being recognized on the books of the Company, the most significant subsidiary of Holdings. The merger transaction resulted in approximately $1.2 billion of goodwill. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets”. The Company reviews its goodwill annually for impairment. The Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the ~~regulated~~performance ~~electric~~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: 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 Consolidated 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 AFDC (see below). Replacement of minor items of utility plant and the cost of current repairs and maintenance are charged to expense. Whenever utility plant is retired, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation.Allowance for Funds Used During Construction (“AFDC”): The Company capitalizes AFDC in amounts equivalent to the cost of funds devoted to plant under construction for its regulated business. AFDC rates are determined in accordance with FERC and PSC regulations. The AFDC rates in effect at March 31, 2003 and 2002 were 1.50 percent and 8.61 percent, respectively. AFDC is segregated into its two components, borrowed funds and other funds, and is reflected in the “Interest charges” and “Other income” sections, respectively, in the Company’s Consolidated Statements of Operations. The amounts of AFDC credits were recorded as follows:

The Power Choice agreement established a five-year electric rate plan that reduced class average residential and commercial prices by an aggregate of 3.2 percent over the first three years, beginning September 1, 1998. On September 1, 1999, Niagara Mohawk implemented its second phase of rate reductions and implemented its third phase of rate reductions on September 1, 2000. The reduction in prices included certain savings that resulted from approved reductions of the GRT. New York State tax law changes that further reduce the GRT rate for some customers and eliminate the GRT for others, are not reflected in the price reductions. The tax law changes are discussed in Item 8. Financial Statements and Supplementary Data, - Note 1. Summary of Significant Accounting Policies, “Basis of Presentation.”

		60 Day Period	30 Day Period	Three Months
	Year Ended	Ended	Ended	Ended	Year Ended
	March 31,	March 31,	January 30,	March 31,	December 31,
	2003	2002	2002	2001	2001	2000
($'s in 000's)	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)
				(Unaudited)
Other income	$ 187	$ 167	$ 136	$ 798	$ 2,296	$ 2,450
Interest charges	384	180	173	906	2,728	3,161

~~Effective~~The ~~August~~above 1,amounts ~~1999, all~~include ofcapitalized ~~Niagara~~interest ~~Mohawk’s~~for ~~customers~~generation ~~were able to choose their electricity supplier. As~~ of ~~December 31, 2001, 9,169 (5~~$0.~~9 percent) of Niagara Mohawk’s~~8 ~~commercial~~million and ~~industrial~~$1.7 ~~customers,~~million orfor ~~approximately~~calendar ~~14.5~~years ~~percent~~ending ofDecember ~~eligible load~~31, 2001 and 392000,~~915 (2~~ respectively.9 There ~~percent)~~was ~~residential~~no ~~customers,~~capitalized orinterest ~~approximately~~for ~~4.0 percent~~generation ofin ~~eligible~~2003 ~~load, have chosen an electricity supplier other than Niagara~~and ~~Mohawk~~2002. ~~See~~Depreciation: For ~~“FERC~~accounting ~~Order~~and ~~888~~regulatory ~~Open~~purposes, ~~Access” below for a discussion of~~the ~~open~~Company’s ~~transmission~~depreciation ~~access~~is ascomputed aon ~~result of~~ the ~~formation~~straight-line ofbasis ~~the~~using ~~NYISO. Niagara~~the ~~Mohawk~~average ~~will~~service ~~continue~~lives tofor ~~distribute~~all ~~electricity~~other ~~through~~classes. The ~~its~~Company ~~transmission~~performs ~~and~~depreciation ~~distribution~~studies ~~systems~~to ~~for~~determine ~~all~~service ~~customers,~~lives ~~regardless~~ of ~~supplier,~~classes ~~and will be provider~~ of ~~last~~property ~~resort~~and ~~for~~adjusts ~~those customers who do not exercise their right to~~the ~~choose~~depreciation arates ~~new~~when ~~electricity supplier~~necessary.The Ifweighted aaverage ~~customer~~service ~~chooses~~life, ~~an alternative~~in ~~supplier~~years, ~~Niagara Mohawk, as allowed under Power Choice, continued to charge the customer~~ for ~~delivery~~each ofasset ~~the~~category ~~energy~~is ~~and~~presented ~~for a non-bypassable CTC charge. Niagara Mohawk also gave a credit to the customer for any services provided by the alternative energy supplier that was provided by Niagara Mohawk~~ in the ~~past.~~ table below:

During the term of the Power Choice agreement, Niagara Mohawk was permitted to defer certain incremental costs associated primarily with environmental remediation and changes in laws, regulations, rules and orders. On August 29, 2001, the PSC approved rate plan changes to cover the final two years of the Power Choice agreement. The rate plan changes allow for implementation of the Power Choice agreement to pass-through certain commodity-related costs to customers beginning September 1, 2001. Electric commodity costs, which fluctuate with market conditions, are projected to be higher as a result of recent trends in commodity markets, increases in charges from the NYISO and the expiration of some Niagara Mohawk supply contracts. Partially offsetting the projected increase in commodity costs is a reduction in overall, system-wide rates for electric delivery service of 5.4 percent associated with a lowering of the competitive transition charge with respect to existing supply contracts. The overall average price increase was projected to be 4.9 percent, with the average residential bill increasing 7.9 percent. Such increases were dependent upon actual commodity market conditions. However, residential and commercial customers were provided with a partial price protection from severe fluctuations in the commodity prices through a delivery charge adjustment mechanism. The Merger Rate Plan described above superseded these rates on January 31, 2002, upon the closing of the merger and continues the pass-through of commodity costs.

		60 Day Period	30 Day Period	Three Months
	Year Ended	Ended	Ended	Ended
	March 31,	March 31,	January 30,	March 31,		Year Ended December 31,
	2003	2002	2002	2001	2001		2000
	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)		(Predecessor)
Asset Category				(Unaudited)

Electric	34	34	33	34	26		28
Gas	42	41	40	41	43		40
Common	17	16	16	16	17		17

Revenues: The Company bills its customers on a monthly cycle basis at approved tariffs based on energy delivered and a minimum customer service charge. Revenues are determined based on these bills plus an estimate for unbilled energy delivered between the cycle billing date and the end of the accounting period. The ~~Power~~unbilled ~~Choice~~revenues ~~agreement~~included in accounts receivable at both March 31, 2003 and 2002 was approximately $132 million.In ~~which~~accordance with the Merger Rate Plan, the Company recognizes changes in accrued unbilled electric revenues in its results of operations. Pursuant to the Company’s 2000 multi-year gas settlement (ending December 2004), changes in accrued unbilled gas revenues are deferred. At March 31, 2003 and 2002, approximately $6 and $13 million, respectively, of unbilled gas revenues remain unrecognized in results of operations. The Company cannot predict when unbilled gas revenues will be allowed to be recognized in results of operations.On August 29, 2001, the PSC approved certain rate plan changes. The changes allowed for certain commodity-related costs to be passed through to customers beginning September 1, 2001. At the same time, a transmission revenue adjustment mechanism was implemented ~~beginning~~which reconciles actual and rate forecast transmission revenues for pass-back to or recovery from customers. The commodity adjustment clause and the transmission revenue adjustment mechanism continue to remain in effect under the Merger Rate Plan which became effective upon the closing of the merger on ~~September~~January 131, 2002.The ~~1998~~PSC approved a multi-year gas rate settlement agreement (ending December 2004) on July 19, ~~provided~~2000 that includes a provision for the ~~recovery~~continuation of ~~deferrals~~a ~~established~~full gas cost collection mechanism, effective August 1, 2000. This gas cost collection mechanism was originally reinstated in ~~years~~an ~~one~~interim ~~through~~agreement ~~four~~that became effective November 1, 1999. Such gas cost collection mechanism continues under the Merger Rate Plan. The Company's gas cost collection mechanism provides for the collection or pass back of increases or decreases in purchased gas costs.Federal and State Income Taxes: As directed by the PSC, the Company defers any amounts payable pursuant to the alternative minimum tax rules. Deferred investment tax credits are amortized over the useful life of the underlying property. Deferred investment tax credits related to the generation ~~sale~~assets that were sold were taken into income in accordance with IRS ~~incentive~~rules. Regulated ~~See~~federal ~~Item~~and 8state income taxes are recorded under the provisions of SFAS No. ~~Financial~~109. Tax ~~Statements~~returns for Holdings and ~~Supplementary~~its ~~Data~~U.S. subsidiaries were filed within National Grid’s consolidated federal tax returns for the periods subsequent to the closing of the merger. Under the National Grid intercompany tax allocation agreement, ~~Note~~Holdings 3and its subsidiaries are allocated federal tax liability based on their separate company liabilities with adjustment for tax benefits associated with any National Grid holding company losses not attributable to acquisition indebtedness. Holdings ~~Rate~~and its New York State business subsidiaries will continue to file a combined New York State tax return.Service Company Charges: National Grid USA Service Company, Inc., an affiliated service company operating pursuant to the provisions of Section 13 of the Public Utility Holding Company Act of 1935, has furnished services to the Company at the cost of such services since the merger with National Grid. These costs amounted to $62 million and ~~Regulatory~~$6 ~~Issues~~million for the year ended March 31, 2003 and ~~Contingencies~~the 60 day period ended March 31, 2002, respectively.Cash and Cash Equivalents: The Company considers all highly liquid investments, purchased with an original maturity of three months or less, to be cash equivalents.Derivatives: The Company adopted SFAS No. 133, “~~Deferred~~Accounting ~~Loss~~for Derivative Instruments and Hedging Activities,” as amended, on January 1, 2001. Upon implementation, the Company designated several financial instruments as derivatives and qualified certain of these instruments as hedges. Those derivative instruments that did not qualify for hedge accounting were the result of regulatory rulings and therefore, the earnings impact of the adoption of SFAS No. 133 was offset by regulatory assets or liabilities as directed by SFAS No. 71. The result was no impact on earnings for the adoption of SFAS No. 133 by the Company. For further discussion of derivatives, see Note J. Derivatives and Hedging Activity.Sale of Customer Receivables: The Company has ~~Assets~~established a single-purpose financing subsidiary, NM Receivables LLC (“NMR”), to purchase and resell a financial interest in a pool of the Company customer receivables. See Note I. Commitments and Contingencies for a complete description of the operations of NMR. The Company adopted SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities - a ~~discussion~~replacement of Financial Accounting Standards Board (“FASB”) Statement 125” in 2001. The Company’s program for selling its accounts receivable meets the ~~generation~~requirements outlined in SFAS No. 140 for recognition and accounting as a sale ~~incentive~~transaction. As ~~The~~a ~~recovery~~result, the adoption of this new standard did not have an impact on the reported ~~deferrals~~financial ~~were~~information ~~limited~~of the Company.Comprehensive Income (Loss): Comprehensive income (loss) is the change in the equity of a company, not including those changes that result from shareholder transactions. While the primary component of comprehensive income (loss) is reported net income or loss, the other components of comprehensive income (loss) relate to additional minimum pension liability recognition, deferred gains and losses associated with hedging activity, and unrealized gains and losses associated with certain investments held as available for sale.Disallowed Nuclear Investment Costs: In 2001, as part of the PSC order approving the sale of the Company’s nuclear assets, the Company wrote-off $123 million of its nuclear investment.New Accounting Standards: In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (“FAS 143”). FAS 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. FAS 143 is effective for fiscal years beginning after June 15, 2002. The Company has evaluated the impact of this standard on its financial position and results of operations. Based on this evaluation the Company does not believe it has any asset ~~remaining~~retirement ~~unamortized~~obligations ~~deferrals~~that would have a significant impact on its results of operations, cash flows, or financial position.In April 2003 the FASB issued SFAS No. 149 “Amendment of Statement 133 on Derivative Instruments and Hedging activities, an amendment of Statement 133” (“FAS 149”). FAS 149 amends and clarifies financial accounting and reporting for derivative instruments and is effective for contracts entered into after June 30, 2003. The Company does not expect the adoption of this statement to have a material effect on its financial position and results of operations.In May 2003 the FASB issued SFAS 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 ~~end~~of the first interim period beginning after June 15, 2003. The Company is currently evaluating the impact of FAS 150 on its financial position ~~year~~and ~~five~~results ~~would~~of operations.Reclassifications: Certain amounts from prior years have been ~~recovered~~reclassified ~~over~~on the accompanying Consolidated Financial Statements to conform to the 2003 presentation. NOTE B – RATE AND REGULATORY ISSUESThe Company’s financial statements conform to GAAP, including the accounting principles for rate-regulated entities with respect to its regulated operations. Substantively, SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” permits a public utility, regulated on a cost-of-service basis, to defer certain costs, which would otherwise be charged to expense, when authorized to do so by the regulator. These deferred costs are known as regulatory assets, which in the case of the Company, are approximately $5.5 billion at March 31, 2003. These regulatory assets are probable of recovery under the Company’s Merger Rate Plan and Gas Multi-Year Rate and Restructuring Agreement. The Company believes that the regulated cash flows to be derived from prices it will charge for electric service in the future, including the Competitive Transition Charges (“CTCs”), and assuming no unforeseen reduction in demand or bypass of the CTC or exit fees, will be sufficient to recover the Merger Rate Plan stranded regulatory assets over the planned amortization period with a return. Under the Merger Rate Plan, the Company’s remaining electric business (electric transmission and distribution business) continues to be rate-regulated on a cost-of-service basis and, accordingly, the Company continues to apply SFAS No. 71 to these businesses. Also, the Company’s Independent Power Producer (“IPP”) contracts, and the Purchase Power Agreements (“PPAs”) entered into in connection with the generation divestiture, continue to be the obligations of the regulated business.In the event the Company determines, as a result of lower than expected revenues and/or higher than expected costs, that its net regulatory assets are not probable of recovery, it can no longer apply the principles of SFAS No. 71 and would be required to ~~exceed~~record ~~five~~an after-tax, non-cash charge against income for any remaining unamortized regulatory assets and liabilities. If the Company could no longer apply SFAS No. 71, the resulting charge would be material to the Company’s reported financial condition and results of operations.Under the Merger Rate Plan, the Company is earning a return on all of its regulatory assets. Merger Rate Plan Stranded Costs: Under the Merger Rate Plan, a regulatory asset was established that included the costs of the Master Restructuring Agreement (“MRA”), the cost of any additional IPP contract buyouts and the deferred loss on the sale of the Company’s generation assets. The MRA represents the cost to terminate, restate or amend IPP contracts. The Company is also permitted to defer and amortize the cost of any additional IPP contract buyouts. Beginning January 31, 2002, the Merger Rate Plan stranded costs regulatory asset is being amortized unevenly over ten years with larger amounts being amortized in the ~~beginning~~latter years, consistent with projected recovery through rates. Regulatory Tax Asset: The regulatory tax asset represents the expected future recovery from ratepayers of the tax consequences of temporary differences between the recorded book bases and the tax bases of assets and liabilities. This amount is primarily timing differences related to depreciation. These amounts are recovered and amortized as the related temporary differences reverse.Loss on Reacquired Debt: The loss on reacquired debt regulatory asset represents the costs to redeem certain long-term debt securities, which were retired prior to maturity. These amounts are amortized as interest expense ratably over the lives of the related issues in ~~year~~accordance ~~six~~with PSC directives.Other: Included in the other regulatory asset is the accumulation of numerous miscellaneous regulatory deferrals, income earned on gas rate sharing mechanisms, the incentive earned on the sale of the fossil and hydro generation assets and certain NYISO costs that were deferred for future recovery. See Notes H, I, and J for a discussion of regulatory asset accounts "Pensions and postretirement benefits", Deferred environmental restoration costs", and "Swap contracts regulatory asset", respectively.NOTE C – ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Beginning in year four of Power Choice, Niagara Mohawk was continuing to recover the cost variations in the indexed swap contracts entered into as part of the MRA, resulting from the indexing provisions of these contracts. As these indexed swap contracts and other contracts expire, the fluctuations in market price of unhedged energy were billed to customers through a commodity adjustment clause. Under the principles established in Power Choice, as these contracts expire, customers who buy electricity from Niagara Mohawk assumed the commodity price risk for energy associated with the expiring contracts. Increases in the cost of natural gas, primarily as it is used as a fuel in electricity generation, raises issues surrounding the ability for ratepayers to absorb such price volatility.

	Unrealized			Total
	Gains and	Minimum		Accumulated
(in 000's)	Losses on	Pension		Other
	Available-for-	Liability	Cash Flow	Comprehensive
	Sale Securites	Adjustment	Hedges	Income (Loss)
December 31, 2001	$ (701)	$ (11,818)	$ (5,126)	$ (17,645)
Purchase accounting adjustments	782	34,899	1,368	37,049
Other comprehensive income (loss):
Unrealized gains (losses) on securities,
net of taxes	45			45
Hedging activity, net of taxes			3,758	3,758
Change in minimum pension liability		(23,081)		(23,081)
March 31, 2002	126	-	-	126
Other comprehensive income (loss):
Unrealized gains (losses) on securities,
net of taxes	(710)			(710)
Hedging activity, net of taxes			600	600
March 31, 2003	$ (584)	$ -	$ 600	$ 16

~~The~~NOTE ~~Power~~D ~~Choice~~– ~~agreement further~~PREFERRED ~~provided~~STOCKThe ~~that~~Company ~~Niagara~~has certain ~~Mohawk~~issues ~~would~~of ~~have~~non-participating apreferred ~~reasonable opportunity to recover its stranded costs~~stock, ~~including~~which ~~those~~provide ~~associated~~for redemption ~~with~~at the ~~MRA~~option ~~and the contracts entered into as part~~ of the ~~MRA~~Company, ~~through~~as ashown ~~CTC and, under certain circumstances, through exit fees or~~ in ~~rates~~the ~~for~~table ~~back up service~~below. From ~~See “FERC~~time ~~Order~~to ~~888~~time ~~- Stranded Cost Recovery in~~ the ~~Case~~Company ofrepurchases ~~Municipalization”~~shares ~~for a further discussion~~ of ~~stranded~~its ~~costs~~preferred ~~and~~stock ~~exit~~when ~~fees.~~it ~~Niagara Mohawk’s rates~~is ~~under~~approached ~~Power Choice were designed to permit recovery of the MRA regulatory asset and to permit recovery of, and a return~~ on, ~~the~~behalf ~~remainder~~ of its ~~assets, as appropriate~~shareholders.

Generation Asset Sales. During 1999, Niagara Mohawk completed the sale of its coal-fired generation plants, its hydro generation plants, and its oil and gas-fired generation plant at Oswego for $860 million. These assets had a combined net book value of approximately $957 million (including materials, supplies and fuel) at the time of their sale. In addition, there were purchase price adjustments of approximately $27 million, primarily due to a lower amount of fuel being delivered to the new owners of the Oswego generation assets than originally anticipated and provided for in the sales agreement. During 2000, Niagara Mohawk completed the sale of its oil and gas-fired plant at Albany for $47.5 million. The Albany plant had a net book value of approximately $36.4 million (including materials, supplies and fuel) at the time of the sale. On January 30, 2001, Niagara Mohawk completed the sale of its 25 percent interest in the Roseton Steam Station for approximately $83.9 million. Niagara Mohawk’s share of the Roseton plant had a net book value of approximately $38.3 million (which includes materials, supplies and fuel) at closing. On November 7, 2001, Niagara Mohawk sold its nuclear assets to Constellation pursuant to which Niagara Mohawk received approximately $271 million in cash and will receive five annual principal and interest payments totaling $332 million. Niagara Mohawk’s share of the plant had a net book value (which includes materials, supplies and fuel) of approximately $1.6 billion as of the closing, excluding the reserve for decommissioning costs.

					Redemption price
	Shares		In 000's		per share
	March 31,	March 31,	March 31,	March 31,	(Before adding
Series	2003	2002	2003	2002	accumulated dividends)
Preferred $100 par value:

3.40%	59,960	64,402	$ 5,996	$ 6,440	$103.50
3.60%	138,199	143,018	13,820	14,302	104.85
3.90%	99,817	102,138	9,982	10,214	106.00
4.10%	55,205	60,721	5,520	6,072	102.00
4.85%	37,228	40,355	3,723	4,036	102.00
5.25%	35,839	36,921	3,584	3,692	102.00

Preferred $25 par value:

Adjustable Rate -
Series D	1,113,100	1,113,100	55,655	55,655	50.00 *

			$ 98,280	$ 100,411

* Not redeemable prior to December 31, 2004.

~~For~~NOTE aE ~~further~~– ~~discussion~~LONG-TERM ~~of these~~DEBTLong-term ~~sales,~~debt ~~see~~consisted ~~Item 8. Financial Statements and Supplementary Data, Note 3. Rate and Regulatory Issues and Contingencies. For a discussion on how Niagara Mohawk used the proceeds from the sale~~ of ~~its generation assets, see~~the ~~“Liquidity and Capital Resources.”~~ following:

Niagara Mohawk signed agreements with the buyers of the plants for energy and capacity at negotiated prices which are above market, based on current energy price forecasts. While the PPAs with the buyers of the formerly owned fossil and hydro assets, which were entered into as an integral part of the sales, are above market, they are designed to help Niagara Mohawk meet rate reduction and price cap commitments as well as expected demand as the provider of last resort. The PPAs converted to either swap agreements or swaptions (swap agreement with a call option.) These swaps act as hedges against a substantial rise in power costs. Niagara Mohawk also signed PPAs with Constellation to purchase energy at negotiated competitive prices for ten years and revenue sharing agreements. See Item 8. Financial Statements and Supplementary Data, Note 3. Rate and Regulatory Issues and Contingencies, Note 8. Commitments and Contingencies, and Note 9. Fair Value of Financial and Derivative Financial Instruments, for a further discussion of the terms of these agreements.

$ in 000's
		March 31,	March 31,		March 31,	March 31,
Series	Due	2003	2002	Series	2003	2002
First Mortgage Bonds:				*Promissory Notes:
5 7/8%	2002	$ -	$ 230,000	2015	$ 100,000	$ 100,000
6 7/8%	2003	85,000	85,000	2023	69,800	69,800
7 3/8%	2003	220,000	220,000	2025	75,000	75,000
8%	2004	232,425	232,425	2026	50,000	50,000
6 5/8%	2005	110,000	110,000	2027	25,760	25,760
9 3/4%	2005	137,981	137,981	2027	93,200	93,200
7 3/4%	2006	275,000	275,000	Note Payable to
*6 5/8%	2013	45,600	45,600	National Grid USA	500,000	-
8 1/2%	2023	-	122,020	Other	8,517	20,443
7 7/8%	2024	170,257	170,257	Unamortized discount	(6,020)	(8,615)
*5.15%	2025	75,000	75,000	Total Long-Term Debt	4,565,641	4,691,289
*7.2%	2029	115,705	115,705	Less long-term debt due
Total First Mortgage				within one year	611,652	544,647
Bonds		1,466,968	1,818,988
					$ 3,953,989	$ 4,146,642
Senior Notes:
7 1/4%	2002	-	302,439
7 3/8%	2003	302,439	302,439
5 3/8%	2004	300,000	300,000
7 5/8%	2005	302,439	302,439
8 7/8%	2007	200,000	200,000
7 3/4%	2008	600,000	600,000
8 1/2%	2010	500,000	500,000
Unamortized discount
on 8 1/2% Senior Note		(22,462)	(60,604)
Total Senior Notes		$ 2,182,416	$ 2,446,713

~~The~~* ~~Power~~Tax-exempt ~~Choice~~pollution ~~agreement~~control related issuesSeveral series of ~~provides~~First ~~for~~Mortgage ~~deferral~~Bonds and ~~future~~Promissory ~~recovery~~Notes were issued to secure a like amount of tax-exempt ~~net~~revenue ~~losses~~bonds ~~resulting~~issued ~~from~~by the ~~sale~~New York State Energy Research and Development Authority (“NYSERDA”). Approximately $414 million of such ~~the~~securities ~~fossil~~bear ~~and~~interest ~~hydro~~at ~~generation~~a ~~asset~~daily ~~portfolio.~~adjustable Ininterest ~~addition,~~rate ~~Niagara~~(with ~~Mohawk~~an ~~was~~option ~~not~~to ~~allowed~~convert to ~~earn~~other rates, including a ~~return~~fixed oninterest rate which would require the ~~deferred~~Company ~~loss~~to ~~during~~issue First Mortgage Bonds to secure the ~~Power~~debt) ~~Choice~~which ~~period~~averaged 1.36 ~~Niagara~~percent ~~Mohawk~~for ~~did~~the ~~not~~year ~~begin~~ended ~~recovery~~March of31, ~~the~~2003, ~~loss~~1.12 onpercent ~~the~~for ~~non-nuclear~~the ~~generation~~three ~~assets~~months ofended ~~approximately~~March ~~$122.5~~31, ~~million~~2002, ~~under~~2.50 ~~Power~~percent ~~Choice~~for 2001, ~~which~~and ~~is included~~4.06 inpercent ~~Niagara~~for 2000 ~~Mohawk’s~~and ~~Consolidated~~are ~~Balance~~supported ~~Sheets~~by asbank ~~“Deferred Loss~~direct onpay ~~Sale~~letters of ~~Assets~~credit.” Pursuant ~~The~~to agreements ~~PSC~~between ~~has~~NYSERDA ~~allowed~~and ~~Niagara~~the ~~Mohawk~~Company, toproceeds ~~offset~~from ~~the~~such issues were used ~~proceeds~~for ~~from~~the purpose of financing the ~~sale~~construction of certain pollution control facilities at the ~~fossil~~Company’s generation facilities or to refund outstanding tax-exempt bonds and ~~hydro~~notes ~~generation~~(see ~~assets~~Note byF). On May 1, 2003, the ~~net~~Company ~~present~~completed ~~value~~the restructuring of ~~the~~$414 ~~amount~~million ~~which~~of variable rate tax exempt bonds. The bonds are currently in the ~~actual~~auction ~~amount~~rate ~~incurred~~mode, onwhich allowed the ~~hydro~~Company ~~PPAs~~to ~~exceeds~~terminate the ~~forecasted~~$424 ~~amount~~million ~~reflected~~of inletter ~~Power~~of ~~Choice.~~credit ~~Pursuant~~facilities that were in place to provide liquidity support for principal and interest while the ~~PSC~~bonds were in a ~~Order~~variable ~~approving~~rate ~~the~~mode.The ~~sale~~aggregate maturities of long-term debt for the five ~~nuclear~~years ~~assets~~subsequent to March 31, ~~dated~~2003, ~~October~~excluding 24capital leases, ~~2001~~in millions, are ~~Niagara~~approximately $612, $533, $550, $279 and $200, respectively. The current ~~Mohawk~~portion of capital lease obligations is reflected in the other current liabilities line item on the Consolidated Balance Sheet and was ~~required~~approximately $1.0 tomillion ~~write-off~~and $~~123~~3.4 million ofat ~~nuclear~~March ~~investment.~~31, 2003 and 2002, respectively. The non-current ~~PSC~~portion of capital lease obligations is reflected in the other ~~Order~~regulatory ~~provides~~and ~~for~~other liabilities line item on the ~~deferral~~Consolidated Balance Sheet and was ~~future~~approximately ~~recovery~~$6 ofmillion and $7 million at March 31, 2003 and 2002, respectively.At March 31, 2003, the ~~remaining~~Company's ~~nuclear~~long-term debt had a fair ~~stranded~~value ~~costs~~of approximately $4.4 ~~Niagara~~billion. ~~Mohawk~~The ~~has~~fair ~~already~~market ~~begun~~value toof ~~amortize~~the Company’s long-term debt was estimated based on the ~~regulatory~~quoted prices for ~~asset~~similar ~~related~~issues toor on the ~~loss~~current onrates offered to the ~~sale~~Company for debt of the same ~~nuclear~~remaining ~~assets~~maturity.Early AsExtinguishment of DebtDuring ~~December~~the year ended March 31, 2003, the three months ended ~~2001~~March 31, ~~Niagara~~2002, ~~Mohawk~~and ~~has~~the ayear ~~regulatory~~ended ~~asset~~December of31, 2000, the Company defeased or redeemed approximately $1122 million,~~074.6~~ $119 million, ~~for~~and ~~the~~$95 ~~net~~million, respectively, ~~loss~~in long-term debt prior to its scheduled maturity. On May on1, 2003, the ~~sale~~Company ofredeemed ~~its~~early ~~nuclear~~$170 ~~generation~~million ~~assets.~~of First Mortgage Bonds. The funds ~~net~~provided ~~loss~~for isthis ~~included~~redemption incame from available cash within the National ~~Niagara~~Grid ~~Mohawk’s~~USA ~~balance~~Money ~~sheet~~Pool. Losses asresulting ~~“Deferred~~from ~~Loss~~the onearly ~~Sale~~redemption of debt ~~Assets.”~~are ~~The~~deferred ~~amount~~and ofamortized ~~this~~as ~~regulatory~~interest ~~asset~~expense ~~related~~ratably toover the ~~sale~~lives of the ~~nuclear~~related ~~assets~~issues isin ~~subject~~accordance towith ~~change~~PSC asdirectives a(see ~~result~~Note ofB).NOTE ~~post~~F – ~~closing~~BANK ~~adjustments~~CREDIT onARRANGEMENTSThe Company had short-term debt ~~the~~outstanding ~~sales,~~of ~~transaction~~$198 ~~costs,~~million ~~subsequent~~and ~~costs~~$419 ~~associated~~million ~~with~~at ~~contract~~March ~~clauses~~31, 2003 and 2002, respectively, from the ~~amount~~inter-company ofmoney ~~severance~~pool. The Company has regulatory approval from the Securities and ~~other~~Exchange ~~costs~~Commission, ~~and~~under ~~PSC~~the ~~review~~Public Utility Holding Company Act of ~~the~~1935, ~~amounts~~to ~~deferred~~issue up to $1 billion of short-term debt. ~~Under~~National ~~the~~Grid ~~Merger~~USA ~~Rate~~and ~~Plan~~certain subsidiaries, ~~Niagara~~including ~~Mohawk~~the ~~has~~Company, ~~agreed~~operate a money pool to ~~forgo~~more ~~collection~~effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of anthe money pool participants. Borrowing companies pay interest at a ~~estimated~~rate ~~$850~~designed ~~million~~to inapproximate ~~nuclear~~the cost of outside short-~~related~~term ~~costs~~borrowings. Companies that ~~otherwise~~invest ~~would~~in ~~have~~the ~~been~~pool share the interest earned on a basis ~~collected~~proportionate to their average monthly investment in ~~rates~~the money pool. Funds ~~Remaining~~may be ~~stranded~~withdrawn ~~costs~~from ~~related~~or repaid to the ~~sale~~pool at any time without prior notice. The Company had a senior bank facility agreement that provided the Company with $424 million for letters of credit ~~all~~with a three-year term. The letter of ~~the~~credit facility ~~generation~~provided ~~assets~~credit ~~and~~support for the ~~MRA~~Company’s adjustable ~~regulatory~~rate ~~asset~~pollution ~~will~~control berevenue ~~amortized~~bonds ~~over~~issued ~~ten~~through ~~years~~the New York ~~based~~State ~~upon~~Energy aResearch ~~pattern~~and ~~established~~Development Authority, discussed in Note E. At March 31, 2003, the ~~Merger~~Company ~~Rate~~had ~~Plan.~~no ~~For~~loans aoutstanding ~~further~~under ~~discussion~~the ofcredit facility. Subsequent to March 31, 2003, the ~~loss~~Company ~~incurred~~converted its daily adjustable rate pollution control revenue bond program to an auction rate mode on ~~these~~May ~~sales~~1, 2003 ~~see~~and ~~Item~~terminated 8the letter of credit facility.NOTE ~~Financial~~G ~~Statements~~– ~~and~~FEDERAL, ~~Supplementary~~STATE ~~Data,~~AND ~~Note~~FOREIGN 3.INCOME ~~Rate~~TAXESFollowing is a summary of the components of federal and ~~Regulatory~~state ~~Issues~~income tax and ~~Contingencies.~~a reconciliation between the amount of federal income tax expense reported in the Consolidated Statements of Income and the computed amount at the statutory tax rate:

Niagara Mohawk has recorded a non-cash incentive as provided for in Power Choice of $18.6 million based on the asset sales of which $9.0 million is reflected in income in 1999, $2.8 million is reflected in income in 2000 and $6.8 million is reflected in income in 2001 in the “Other income (deductions)” line item of the Consolidated Income Statements. The incentive earned reflects PSC Staff recommended adjustments based on their review to date and is included in the other regulatory assets on the Consolidated Balance Sheets. The Power Choice agreement provides for recovery of the incentive beginning in 2001, over a period not to exceed five years. The Merger Rate Plan modifies the recovery period of stranded costs and incentives.

		60 Day Period	30 Day Period	Three Months
	Year Ended	Ended	Ended	Ended
	March 31,	March 31,	January 30,	March 31,	Year Ended December 31,
	2003	2002	2002	2001	2001	2000
In thousands of dollars				(Unaudited)
	(Sucessor)	(Sucessor)	(Predecessor)	(Predecessor)	(Predecessor)

Components of federal, state and
foreign income taxes:

Current tax expense (benefit):
Federal	$ (34,908)	$ (1,672)	$ 10,395	$ 6,519	$ 3,637	$ 17,908
State	14,320	(6,698)	357	430	386	468
	(20,588)	(8,370)	10,752	6,949	4,023	18,376
Deferred tax expense (benefit):
Federal	111,157	24,106	(6,194)	11,108	(84,073)	(26,523)
State	(344)	10,098	(780)	(1,109)	1,178	(5,422)
	110,813	34,204	(6,974)	9,999	(82,895)	(31,945)

Total	$ 90,225	$ 25,834	$ 3,778	$ 16,948	$ (78,872)	$ (13,569)


Total income taxes in the consolidated
statements of operations:
Income taxes charged/
(credited) to operations	$ 93,277	$ 26,362	$ 4,036	$ 24,368	$ 9,582	$ (6,201)
Income taxes credited to
"Other Income (deductions)"	(3,052)	(528)	(258)	(7,420)	(88,454)	(7,368)

Total	$ 90,225	$ 25,834	$ 3,778	$ 16,948	$ (78,872)	$ (13,569)

~~The~~Reconciliation ~~MRA~~between ~~Agreement. As a result of various~~ federal ~~and~~income ~~state~~taxes ~~requirements, Niagara Mohawk was required to enter into contracts to purchase electricity from IPPs in quantities in excess of its own demand~~ and at prices in excess of those available to it. In mid-1996, Niagara Mohawk began comprehensive negotiations to terminate, amend or restate a substantial portion of above-market PPAs in an effort to mitigate the ~~escalating~~ ~~cost~~tax ofcomputed ~~these PPAs as well as to prepare Niagara Mohawk for a more~~at ~~competitive~~prevailing ~~environment~~U.S. ~~These~~statutory ~~negotiations~~rate ~~led~~on toincome ~~the~~before ~~MRA~~income ~~and the Power Choice agreement.~~ taxes:

The MRA was consummated on June 30, 1998 with 14 IPPs. The MRA allowed Niagara Mohawk to terminate, restate or amend 27 PPAs which represented approximately three-quarters of its over-market purchased power obligations. Niagara Mohawk terminated 18 PPAs for 1,092 MW of electric generating capacity, restated 8 PPAs representing 535 MW of capacity and amended 1 PPA representing 42 MW of capacity. Niagara Mohawk paid the IPP Parties an aggregate of $3.934 billion in cash, of which $3.212 billion was obtained through a public market offering of senior unsecured debt, $303.7 million from the public sale of 22.4 million shares of common stock, and the remainder from cash on hand. In addition, Niagara Mohawk issued 20.5 million shares of common stock to the IPP Parties.

			30 Day Period	Three Months
	Year Ended	60 Day Period	Ended	Ended
	March 31,	March 31,	January 30,	March 31,	Year Ended December 31,
	2003	2002	2002	2001	2001	2000
				(Unaudited)
Computed tax	$ 75,641	$ 19,768	$ (5,883)	$ 17,835	$ (20,830)	$ (14,425)
	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)	(Predecessor)
Increase (reduction) including those attributable to
flow-through of certain tax adjustments:

Depreciation	12,183	3,202	1,493	17,112	18,620	27,366
Cost of removal	(6,730)	(1,139)	(583)	(7,682)	(6,441)	(6,936)
Allowance for funds used
during construction - (a)	642	133	47	(1,527)	(806)	(1,179)
State income taxes	20,174	2,541	1,839	(765)	1,564	(4,954)
Non-deductible Executive
compensation	(9,878)	-	9,878	-	-	-
Accrual to return adjustment	6,934	-	-	-	-	-
Goodwill Adjustments	-	-	(1,953)	-	-	-
Pension settlement amortization	-	-	-	-	-	(758)
Debt premium & mortgage
recording tax	3,196	275	51	661	664	806
Real estate taxes	(9,300)	-	-	-	(414)	(5,860)
Amortization of capital stock	-	-	40	661	548	634
Dividends exclusion - federal
income tax returns	-	(67)	(34)	(486)	(468)	(517)
Provided at other than statutory
rate	(2)	4	(2)	-	(4)	(1,186)
Supplemental Executive
Retirement trust fund	-	-	-	-	-	(446)
Settlement of IRS exams	-	-	-	-	-	(1,852)
Voluntary Early Retirement
Plan	(251)	-	-	-	11,272	-
Allocation Percentage/Annualization	-	-	-	(3,002)	-	-
Subsidiaries		(173)	(96)	(313)	(1,115)	3
Deferred investment tax credit
reversal (b)	(3,029)	(528)	(258)	(7,420)	(86,034)	(6,110)
Other	645	1,818	(761)	1,874	4,572	1,845
	14,584	6,066	9,661	(887)	(58,042)	856
Federal income taxes	$ 90,225	$ 25,834	$ 3,778	$ 16,948	$ (78,872)	$ (13,569)

~~Power~~(a) ~~Choice~~Includes ~~provided~~Carrying ~~that the~~Charges ~~MRA~~(Interest ~~and~~Expense) ~~the~~imposed ~~contracts~~by ~~executed as part of~~ the ~~MRA were prudent and~~ ~~accordingly,~~ PSC ~~approval of Power Choice allowed Niagara Mohawk to record a regulatory asset for the costs of the MRA, which is being amortized over a period generally not to exceed ten years~~. Niagara Mohawk’s rates under Power Choice were designed to permit recovery of the MRA regulatory asset. The Power Choice agreement had the effect of substantially depressing earnings during its term and substantially improving operating cash flow. The closing of the merger and the implementation of the Merger Rate Plan will impact the future results of Niagara Mohawk. See “Merger Rate Plan” for a further discussion of how the closing of the merger with National Grid will impact the future results of Niagara Mohawk.

~~The~~(b) Deferred ~~MRA~~investment ~~had~~tax ~~the~~credits ~~effect~~ of ~~reducing~~ ~~Niagara~~$79.7 ~~Mohawk’s~~million ~~IPP~~and ~~payments by more than~~ $~~500~~0.8 million ~~annually~~ inrelated ~~1998 and 1999 as compared~~ to ~~leaving~~ the ~~pre-existing~~generation ~~contracts~~assets inthat ~~place,~~have ~~net of~~been ~~purchases~~sold ~~of power at market price. These savings~~ have been ~~partially~~taken ~~reduced~~into income in ~~2000~~2001 and ~~2001~~2000, asrespectively, ain ~~result~~accordance ofwith ~~the~~IRS ~~increase in commodity prices~~rules. The ~~resulting~~deferred ~~improvement~~tax inliabilities ~~cash~~(assets) ~~flow~~were ~~and~~comprised ~~the proceeds from the sale~~ of the ~~generation assets have allowed Niagara Mohawk to repay debt and repurchase Holdings’ common stock.~~ following:

Under the terms of the MRA, Niagara Mohawk has no continuing obligation to purchase energy from the terminated IPP Parties. The restated contracts with eight PPAs reflect economic terms and conditions that are more favorable to Niagara Mohawk than the previous PPAs. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and Item 8. Financial Statements and Supplementary Data - Note 8. Commitments and Contingencies and Note 9. Fair Value of Financial and Derivative Financial Instruments, for a further discussion regarding the remaining payments to the IPP Parties for the purchase of electric power and the payments made under the swap agreements.

In thousands of dollars	March 31,	March 31,
	2003	2002
	(Successor)	(Successor)
Alternative minimum tax	$ 81,639	$ 96,481
Unbilled revenues	16,890	23,052
Non-utilized NOL carryforward	554,821	607,292
Liability for environmental costs	131,750	126,225
Voluntary early retirement program	199,980	249,150
Other	341,850	286,657
Total deferred tax assets	1,326,930	1,388,857

Depreciation related	(857,711)	(810,180)
Investment tax credit related	(46,075)	(49,115)
Deferred environmental restoration costs	(131,750)	(126,225)
Merger rate plan stranded costs	(1,158,204)	(1,169,525)
Merger fair value pension and OPEB adjustment	(163,890)	(188,856)
Other	(91,638)	(103,484)
Total deferred tax liabilities	(2,449,268)	(2,447,385)

Net accumulated deferred income
tax liability	$ (1,122,338)	$ (1,058,528)

~~Niagara~~In ~~Mohawk~~December ~~has~~1998, ~~pursued~~the Company received a ruling from the IRS which provided ~~other~~that ~~opportunities~~the toamount ~~reduce~~of ~~its~~cash ~~payments~~and tothe ~~IPPs~~value of common stock that ~~were~~was ~~not~~paid ~~party~~by the Company to the subject terminated IPP Parties was deductible in 1998 which ~~MRA.~~resulted ~~Under~~in ~~Power~~the ~~Choice,~~Company ~~Niagara~~not ~~Mohawk~~paying isany ~~permitted~~regular tofederal ~~defer~~income taxes for 1998, and ~~amortize~~further ~~the~~generated a substantial net operating loss for federal income tax ~~cost~~purposes. The Company carried back a portion of ~~any~~the ~~additional~~unused ~~IPP~~NOL ~~contract~~to ~~buyouts.~~the Inyears 1996 ~~1999~~and 1997, and also for the years 1988 through ~~2001~~1990, 13which ~~IPP~~resulted in ~~contracts~~federal ~~for~~income ~~approximately~~tax ~~161~~refunds MWof $135 million that were ~~terminated~~received ~~for~~in January 1999. As a ~~total~~result ~~consideration~~of the merger with National Grid, the Company is now part of the consolidated tax return filing group of National Grid General Partnership (~~cash~~the parent ~~and/or~~company, ~~notes~~through an intermediary entity, of National Grid). The Company anticipates that the consolidated tax filing group will be able to utilize the remaining NOL carryforward prior to its expiration in 2019. The amount of the NOL carryforward as of March 31, 2003 is $~~242.~~1.568 ~~million~~billion. National ~~Deferred~~Grid’s ability ~~costs~~to ~~associated~~utilize ~~with~~the ~~IPP buyouts~~NOL ~~must~~carryforward ~~generally~~generated beas ~~amortized~~a ~~over~~result ~~five~~of ~~years,~~the ~~unless~~MRA ~~PSC~~and ~~approval~~the utilization of alternative minimum tax credits is affected by the rules of ~~obtained~~Section ~~for~~382 of the Internal Revenue Code.NOTE H – PENSION AND OTHER RETIREMENT PLANSThe Company has a ~~different~~non-contributory ~~amortization~~defined benefit ~~period~~pension plan covering substantially all employees. The ~~Niagara~~plan ~~Mohawk~~includes ~~retains~~a cash balance benefit in which the ~~annual~~participant has an account to which amounts ~~net~~are ~~savings~~credited ~~from~~based ~~the~~on ~~buyouts~~qualifying ~~during~~compensation and with interest determined annually based on the ~~remaining~~average ~~term~~annual of30-year ~~Power~~Treasury ~~Choice~~bond toyield. Supplemental non-qualified, ~~offset~~non-contributory executive retirement programs provide additional defined pension benefits for certain executives. In addition, the ~~amortization~~Company provides ~~expense~~certain contributory health care and life insurance benefits for active and retired employees and dependents.The changes in benefit obligations, plan assets and plan funded status for these pension and other retirement plans are summarized as follows:

FERC Order 888. In April 1996, FERC issued Order 888, which promotes competition by requiring that public utilities owning, operating, or controlling interstate transmission facilities file tariffs which offer others the same transmission services they provide for themselves, under comparable terms and conditions. FERC Order 888 required state power pools to file reformed power pooling agreements that establish open, non-discriminatory membership provisions and modify any provisions that are unduly discriminatory or preferential. In addition, the FERC Order also provides for the recovery of prudent and verifiable stranded costs where the wholesale customer was able to obtain alternative power supplies as a result of Order 888‘s open access mandate.

In thousands of dollars	Pension Benefits		Other Retirement Benefits
	March 31,	March 31,	March 31,	March 31,
	2003	2002	2003	2002
Change in benefit obligation:	(Successor)		(Successor)

Benefit obligation at April 1	$ 1,231,149	$ 1,246,620	$ 743,289	$ 651,423
Service cost	24,970	7,752	6,745	2,412
Interest cost	83,493	22,453	55,551	12,599
Benefits paid to participants	(53,049)	(49,100)	(56,753)	(11,402)
Plan amendments	12,150	-	-	15,012
Curtailments	-	-	-	-
Settlements	(172,427)	(79,165)	-	-
Actuarial (gain) loss	173,522	12,915	183,764	64,674
Dispositions	(3,148)
Special Termination Benefits	-	69,674		8,571
Benefit obligation at end of period	1,296,660	1,231,149	932,596	743,289

Change in plan assets:

Fair value of plan assets at April 1	988,535	1,076,277	276,870	268,740
Contributions	97,794	23,404	81,175	-
Net return on plan assets	(120,801)	2,500	(27,296)	8,130
Benefits paid to participants	(53,049)	(49,100)	-	-
Dispositions	(2,459)
Settlements	(172,427)	(64,546)	-	-
Fair value of plan assets at end of period	737,593	988,535	330,749	276,870

Reconciliation of accrued cost at
end of period:
Funded status	(559,067)	(242,614)	(601,847)	(466,419)
Unrecognized prior service cost	12,150	-		-
Unrecognized net (gain) loss	324,931	(9,631)	208,454	(26,729)
Net amount recognized at end of period	$ (221,986)	$ (252,245)	$ (393,393)	$ (493,148)

Amounts recognized on the consolidated
balance sheets consist of:

Employee pension and other benefits liability	$ (490,811)	$ (252,245)	$ (393,393)	$ (493,148)
Intangible asset	12,150
Regulatory asset	256,675
Net amount recognized at end of period	$ (221,986)	$ (252,245)	$ (393,393)	$ (493,148)

The Dispositions noted in the table above relate to the spin-off of the assets and liabilities in conjunction with the sale of NM Energy. As part of the acquisition by National Grid, the Company made certain change-of-control payments under the supplemental non-qualified executive retirement program and offered a ~~result~~voluntary early retirement program (“VERP”) to selected employees in areas targeted for staffing reductions. These items appear in the tables as Special Termination Benefits. At the time of ~~Order~~the ~~888~~merger with National Grid, ~~there~~the ~~have~~Company ~~been~~revalued ~~several~~its assets ~~developments~~and ~~during~~liabilities to their fair value in accordance with purchase accounting. This revaluation resulted in an increase to the ~~past~~Company’s pension ~~few~~and ~~years~~postretirement asbenefit ~~follows:~~plan liabilities in the amount of approximately $440 million, with a corresponding offset to a regulatory asset account, which is being amortized ratably over the ten year period beginning January 31, 2002. The costs of the change-of-control payment under the non-qualified plan were charged to expense. The following table sets forth the components and disposition of payments made in the prior period:

Open Access

(in millions of dollars)
	Charged to Expense	Deferred in Merger Rate Plan Stranded Cost	Totals
Pension benefits	$ 25.7	$ 44.0	$ 69.7
Other post-retirement benefits		8.6	8.6
	$ 25.7	$ 52.6	$ 78.3

~~The~~For ~~New~~the ~~York~~year ~~Power~~ended ~~Pool~~March ~~was~~31, ~~restructured~~2003, as the ~~NYISO~~Company had a net settlement loss of $29.5 ~~The~~million ~~NYISO~~relating ~~commenced~~to ~~formal~~normal ~~operations~~lump-sum ondistributions ~~December~~and 1,the ~~1999~~spin-off of the assets and liabilities related to the sale of NM Energy. For ~~Niagara~~the ~~Mohawk~~60 ~~believes~~Day Period ended March 31, 2002, the ~~NYISO~~Company ~~promotes~~had a ~~more~~net ~~competitive~~settlement ~~market~~gain ~~for~~of ~~wholesale~~$16.7 ~~electricity~~million related ~~supply~~to ~~service~~the insale ~~New~~of ~~York~~its ~~State~~nuclear assets. In A2001, ~~discussion~~the Company experienced a net curtailment/settlement loss of $31.9 million due to the ~~financial~~employee transfers associated with the sale of the nuclear assets and ~~accounting~~change ~~impacts~~of ascontrol apayments under ~~result~~the supplemental executive retirement plan. Of the 2001 loss, $11.2 million is recorded in the deferred loss on the sale of assets, $6.0 million is due from co-tenants for their allocation of the ~~transition~~plant ownership and $14.7 million was charged to expense. The non-qualified executive pension plan has no plan assets due to the ~~NYISO~~nature isof ~~included~~the plan and, therefore, has an accumulated benefit obligation in excess of plan assets of $ 9.2 million, $19.6 million and $17.3 million at March 31, 2003, 2002 and December 31, 2001, respectively.The following table summarizes the ~~results~~components of ~~operations~~the ~~section~~net annual benefit costs.

Stranded Cost Recovery in the Case of Municipalization

	In thousands of dollars
	Pension Benefits				Other Postretirement Benefits
		60 Day	30 Day			60 Day	30 Day
	Year	Period	Period		Year	Period	Period
	Ended	Ended	Ended		Ended	Ended	Ended
	March 31,	March 31,	January 30,	December 31,	March 31,	March 31,	January 30,	December 31,
	2003	2002	2002	2001	2003	2002	2002	2001
	(Successor)		(Predecessor)		(Successor)		(Predecessor)
Service cost	$ 24,970	$ 4,886	$ 2,866	$ 32,046	$6,745	$1,348	$1,064	$11,265
Interest cost	83,493	14,637	7,816	88,315	55,551	8,806	3,792	41,664
Expected return
on plan assets	(75,613)	(14,751)	(7,567)	(94,247)	(23,642)	(3,458)	(2,071)	(24,436)
Amortization of the
initial obligation	-	-	191	2,240	-	-	908	10,890
Amortization of
gains and losses	5,559	-	(174)	(1,122)	(498)	-	1,332	7,101
Amortization of prior
service costs	-	-	801	8,464	-	-	302	(7,207)

Net benefit cost before
curtailments and
settlements	38,409	4,772	3,933	35,696	38,156	6,696	5,327	39,277
Curtailment (gain) loss	-	-	-	14,063	-	-	-	3,179
Settlement (gain) loss	29,548	(16,726)	-	14,689	-	-	-	-
Special Termination Benefits		44,000	25,674	-	-	8,571	-	-

Net benefit cost ⁽¹⁾	$ 67,957	$ 32,046	$ 29,607	$ 64,448	$ 38,156	$ 15,267	$ 5,327	$ 42,456

In(1) ~~Order~~A ~~888,~~portion ~~the~~of ~~FERC stated that it would provide for~~ the ~~recovery~~benefit ~~of prudent and verifiable wholesale stranded~~ costs ~~where~~relates ~~the wholesale customer was able~~ to ~~obtain~~construction ~~alternative~~labor, power supplies as a result of Order 888‘s open access mandate. Order 888 left to the states the issue of retail stranded cost recovery. Where newly created municipal electric utilities required transmission service from the displaced utilityand accordingly, ~~the FERC stated that it would entertain requests for stranded cost recovery to the extent that such municipalization~~ is ~~made~~allocated ~~possible by open access. The FERC also reserved the right~~ to ~~consider~~construction ~~stranded costs on a case-by-case basis if it appeared that open access was being used to circumvent stranded cost review by any regulatory agency~~projects.

In November 1997, FERC issued Order 888-B. This Order clarified that the FERC recognizes the existence of concurrent state jurisdiction over stranded costs arising from municipalization. The FERC acknowledged in Order 888-B that the states may be first to address the issue of retail-turned-wholesale stranded costs, and stated that it will give the states substantial deference where they have done so.

		Pension Benefits				Other Retirement Benefits

	March 31,		March 31,	December 31,	March 31,		March 31,	December 31,
	2003		2002	2001	2003		2002	2001
Weighted average assumptions
Discount rate	6.25%		7.50%	7.25%	6.25%		7.50%	7.25%
Expected return on plan assets	8.50		8.75	9.50	8.50		8.50	9.25
Rate of compensation increase
(plus merit increases)	3.25		3.25	2.50	N/A		N/A	N/A
Health care cost trend rate:
2002	N/A		N/A	N/A	N/A		10.00	9.00
2003	N/A		N/A	N/A	10.00		9.00	8.00
2004	N/A		N/A	N/A	9.00		8.00	7.00
2005	N/A		N/A	N/A	8.00		7.00	6.00
2006	N/A		N/A	N/A	7.00		6.00	5.00
2007	N/A		N/A	N/A	6.00		5.00	5.00
2008 and Thereafter	N/A		N/A	N/A	5.00		5.00	5.00

InThe ~~approving~~assumed ~~Power~~health ~~Choice,~~cost ~~the~~trend ~~PSC~~rates ~~authorized~~decline ~~changes~~ to ~~Niagara~~five ~~Mohawk’s~~percent ~~Retail Tariff providing for the recovery of stranded costs~~ in ~~the~~2008 ~~case~~and remain ofat ~~municipalization~~that ~~regardless~~level ~~of whether the new municipal utility requires transmission service from Niagara Mohawk~~thereafter. The ~~calculation~~assumed ofhealth ~~stranded~~cost ~~costs~~trend ~~for~~rates ~~customers~~can ~~leaving~~have ~~Niagara Mohawk’s system to be supplied by~~ a significant ~~municipal~~effect oron ~~other~~the ~~utility~~amounts orreported ~~IPP~~for isthe ~~governed~~health bycare ~~Rule 52 of Niagara Mohawk’s Retail Tariff, which became effective on April 6, 1998~~plans. A one-percentage-point ~~number~~change ofin ~~communities~~assumed ~~served~~health bycare ~~Niagara~~cost ~~Mohawk~~trend ~~are~~rates ~~considering~~would ~~municipalization and~~ have the ~~requested~~following ~~an estimate of their stranded cost obligation.~~effects:

In the PSC Order approving the merger and long-term rate settlement, the PSC approved certain modifications to Rule 52. In brief, these modifications are: (1) Rule 52 will not apply to a customer’s premises which is disconnected from the Niagara Mohawk system and is supplied by generation installed after the effective date of the Merger Rate Plan when the generator is used exclusively to serve the customer; and (2) under specified circumstances when the customer disconnects from the Niagara Mohawk system and is connected to generation located on or immediately adjacent to the customer’s premises. The approved settlement provides that it does not preclude the parties from advocating that the Commission modify or eliminate Rule 52 or the Commission from adopting different policies on its own.

	1% Increase	1% Decrease
	(in thousands of dollars)
Effect on total of service and interest
cost components of net periodic
postretirement health care benefit cost	$ 6,894	$ (6,140)

Effect on the health care component of
the accumulated postretirement
benefit obligation	$ 91,180	$ (82,943)

~~Lakewood~~Regulatory treatment of pensions and postretirement benefit plans: In addition to the regulatory assets established in connection with purchase accounting and the additional minimum pension liability discussed above, the regulatory asset account “Pension and postretirement benefit plans” includes certain other components. First, the Company is required under the Merger Rate Plan to defer the difference between pension and postretirement benefit expense and the allowance in rates for these costs. Also, the regulatory asset account includes the $52 million cost of the VERP discussed above, and a postretirement benefit phase-in deferral established in the mid-1990’s. The VERP is being amortized unevenly over the 10 years of the Merger Rate Plan with larger amounts being amortized in the earlier years. VERP amortization in fiscal 2003 was approximately $17 million. The phase-in deferral is being amortized at a rate of approximately $3 million per year.Additional Minimum Pension Liability: Statement of Financial Accounting Standards No. 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, 2003 is greater than the fair value of plan assets. As such, the Company has recognized an additional minimum pension liability of $269 million on its balance sheet reflecting this underfunded pension obligation. The Company would normally record a charge to other comprehensive income as an offset to this entry. However, due to the nature of its rate plan the Company has not charged other comprehensive income but has instead recorded a regulatory asset. If in the future, capital markets recover such that the fair value of plan assets is once again greater than the ABO, the additional minimum pension liability will be removed from the Company's balance sheets.Defined Contribution Pension Plan: The Company also has a defined contribution pension plan (employee savings fund plan) that covers substantially all employees. Employer matching contributions of $8.0 million, $2.2 million and $10.0 million were expensed for the twelve months ended March 31, 2003, the three months ended March 31, 2002, and the year ended December 31, 2001 respectively.Postemployment Benefits: The Company recognizes the obligation to provide post-employment benefits if the obligation is attributable to employees’ past services, rights to those benefits are identified in the plan documents, payment is probable and the amount of the benefits can be reasonably estimated. At March 31, 2003 and March 31, 2002, the Company’s post-employment benefit obligation is approximately $33.5 million and $23.3 million, respectively.NOTE I – COMMITMENTS AND CONTINGENCIESCommodity Reconciliations: As part of the Company's ongoing reconciliation of commodity costs and revenues, the Company has identified several adjustments and included them in filings with the PSC. Specifically, the Company has requested recovery of $36 million of commodity costs associated with the under-reconciliation of New York Power Authority (“NYPA”) hydropower revenues in its commodity adjustment clause, and is proposing to refund $24 million associated with other revenues that were not included in the commodity adjustment reconciliation. In addition, the Company has filed a modification to its tariff and a proposal to refund an additional $7 million associated with the recovery of other NYPA hydropower costs. These filings are pending before the PSC, and the Company cannot predict the outcome of the filings.Long-Term Contracts for the Purchase of Electric Power: The Company has several types of long-term contracts for the purchase of electric power. The Company’s commitments under these long-term contracts, as of March 31, 2003, excluding its commitments with New York Power Authority (“NYPA”), which are shown separately, are summarized in the table below. The Company did not enter into any new agreements in fiscal 2003. Following the table are descriptions of the different types of these long-term contracts. For a detailed discussion of the financial swap agreements that the Company has entered into as part of the MRA and the sale of its generation assets (the sale of the Huntley and Dunkirk coal-fired generation plants and the sale of the Albany oil and gas-fired generation plant) which are not included in the table below, see Note J. Derivatives and Hedging Activity.

In August 1997, Niagara Mohawk provided the Village of Lakewood (“Lakewood”) with an estimate of its stranded cost obligations under both Rule 52 and FERC Order No. 888. In June 1998, Lakewood filed a petition with FERC seeking a determination that it would not be responsible for any of Niagara Mohawk’s stranded costs if it created a new municipal electric system.

	(In thousands of dollars)
	Estimated	Estimated		Estimated		Estimated
Fiscal Year	Fixed Costs	Variable Costs		Purchased		Purchased
Ended		Capacity,		Capacity		Energy
March 31,	Capacity	Energy and Taxes **	Total	(in MW)		(in MWh)

2004	$32,286	$516,428	$548,714	3,255		12,006,579
2005	17,397	465,687	483,084	2,033		10,834,411
2006	15,207	382,243	397,450	1,406		8,815,387
2007	15,337	389,079	404,416	1,402		9,403,215
2008	14,836	371,665	386,501	1,385		8,757,187
2009-2017	44,736	1,823,906	1,868,642	674	*	34,165,526

On∗ MW ~~December~~value ~~11,~~represents ~~1998,~~ the ~~FERC~~average ~~issued~~annual anquantity ~~order granting Niagara Mohawk’s request for clarification that Order No. 888 does not preempt the exit fee provision~~ of the Retail Tariff and directing that Lakewood’s case before the FERC be held in abeyance pending the resolution by the PSC of Lakewood’s stranded cost obligation under the exit fee provisions of Niagara Mohawk’s Retail Tariff.purchased capacity

~~During~~∗∗ Does ~~1999,~~not include puts (see below)PURPA ContractsUnder the ~~PSC~~requirements ~~established~~of athe ~~formal~~Public ~~proceeding~~Utilities inRegulatory Policies ~~this~~Act ~~matter.~~of ~~Niagara~~1978, ~~Mohawk~~as ~~filed~~amended ~~its~~(“PURPA”), ~~direct~~the ~~case~~Company onis ~~September~~required to 3purchase power generated by IPPs, ~~1999~~as defined therein. The Company has 104 PPAs with 112 IPP facilities, ~~which~~amounting ~~supported~~to aapproximately ~~revised~~505 ~~estimate~~MW of ~~exit~~capacity ~~fees~~at March 31, 2003. All of ~~$18~~this ~~million~~capacity amount is considered firm and excludes PPAs that provide energy only. The ~~Lakewood~~table ~~filed~~above ~~its~~includes ~~direct~~the ~~case~~estimated onpayments for ~~October~~fixed 18costs (capacity) and variable costs (capacity, ~~1999~~energy and related taxes) that the Company estimates it will be obligated to make under these 104 IPP contracts, ~~which~~excluding ~~supported~~the anput ~~exit~~contracts ~~fee~~(see ofbelow) ~~approximately~~and $5the ~~million.~~financial obligation under the swap contracts. The ~~parties~~payments to the ~~case~~IPPs ~~subsequently~~are ~~entered~~subject ~~into~~to the atested ~~number~~capacity and availability of ~~stipulations~~the ~~that~~facilities, ~~subject~~scheduling ~~any~~and ~~exit~~price escalation. These ~~fee~~payments ~~established~~have been significantly reduced by the ~~Commission~~consummation of the MRA and additional IPP restructurings made in 1999 and 2000.Fixed capacity costs (in the table above) relate to three contracts as follows: 1) a contract ~~true-up~~with ~~based~~an onIPP, 2) a contract entered into along with the ~~resolution~~sale of ~~certain~~the Oswego ~~issues~~generation ~~presented~~assets inas ~~other~~discussed ~~proceedings~~further orbelow, ~~forums~~and 3) the contract entered into along with the sale of the hydroelectric generation assets as discussed further below. With ~~These~~respect ~~include~~to ~~stipulations~~the ~~which~~IPP ~~call~~contract, the Company is required to make capacity payments, including payments when the facility is not operating but available for ~~ultimate~~service. The ~~determinations~~terms ~~outside~~of this ~~case~~contract ofallow the ~~amortization~~Company ~~period~~to schedule energy deliveries and then pay for ~~regulatory~~the ~~assets~~energy delivered. Contracts relating to the remaining IPP facilities in service at March 31, 2003 require the Company to pay only when energy is delivered. The Company paid approximately $266 million, $90 million, $321 million, and ~~return~~$416 onmillion ~~Niagara~~in ~~Mohawk’s~~the year ~~regulatory~~ended ~~assets~~March ~~for~~31, ~~nuclear~~2003, ~~stranded~~the ~~costs~~three months ended March 31, 2002, and the ~~MRA~~years end December 31, 2001 and ~~loss~~2000 onfor 2,389,000 MWh, 671,000 MWh, 3,340,000 MWh, and 5,077,000 MWh, respectively, of electric power under all IPP contracts.Fossil/Hydro ContractsAs part of the sale of the Company’s fossil and hydro generation assets, the Company entered into PPAs with the buyers of these assets for the purchase of capacity and energy. The hydro PPA calls for the purchase of all energy and capacity through September 2004 at prices that approximate forecasted future market prices. The Company anticipates that the energy and capacity to be purchased under the hydro PPA to be at quantities approximating historical generation levels, subject to the effects of water flow availability. The Oswego PPA is primarily a contract for capacity with a nominal amount of energy at prices above forecasted future market prices. The table above includes the estimated payments for variable costs and quantities (capacity and energy) associated with the PPAs that the Company estimates it will make under these contracts. The Company paid approximately $161 million in the year ended March 31, 2003, $33 million in the three months ended March 31, 2002, $109 million in 2001, and $137 million in 2000 for 3,125 MW, 2,769 MW, 2,945 MW, and 1,948 MW of capacity and 2,749,000 MWh, 677,186 MWh, 2,573,000 MWh, and 3,274,000 MWh of electric power, respectively, under these PPAs.

Nuclear Contracts

OnThe ~~September~~table ~~11,~~above ~~2000~~includes the estimated payments for variable costs and quantities (capacity and energy) associated with the PPAs entered into with the buyers of the nuclear generation assets. As part of the agreement with Constellation to sell its nuclear generation assets, the ~~PSC~~Company ~~issued~~entered aninto PPAs ~~order~~to ~~setting~~purchase ~~Lakewood’s~~90 ~~exit~~percent ~~fee~~of the actual hourly nuclear plant output for its percentage interest of the nuclear plants at what are currently believed to be competitive prices for approximately ~~$14~~8 years (Unit 1) and 10 years (Unit 2).5 The ~~million,~~Company ~~subject~~pays toonly ~~certain~~for ~~adjustments~~delivered output from the units. Upon Inthe ~~that~~expiration of ~~order~~the PPA for Unit 2, ~~the~~there ~~PSC~~is ~~also~~a ~~directed~~revenue ~~that~~sharing ~~further~~agreement ~~proceedings~~whereby bethe ~~conducted~~Company is entitled to ~~determine~~future ~~whether~~payments from Constellation over a ten-year period if electric energy and capacity market prices exceed certain ~~changes~~amounts toduring ~~Rule~~the ten-year 52sharing ~~should~~period. The Company would not be ~~implemented~~required atto ~~the~~buy ~~expiration~~energy offrom Constellation, LLC under the ~~five~~revenue ~~year~~sharing ~~term~~agreement. Purchases ofunder ~~Power~~the nuclear ~~Choice~~PPAs began in November 2001. The ~~Lakewood~~Company ~~has~~paid ~~requested~~approximately ~~rehearing~~$269 million for 7,390,000 MWh of electric power and 985 MW of capacity in the ~~PSC’s~~year ended ~~September~~March 1131, ~~2000~~2003, ~~order~~$61 million for 1,946,000 ~~and~~MWh ~~this~~of ~~rehearing~~electric ~~request~~power isand ~~still~~1,086 MW ~~pending~~of ~~before~~capacity in the ~~PSC.~~three Onmonths ~~February~~ended 14March 31, ~~2001~~2002, ~~the~~and ~~Attorney~~$38 ~~General~~million for 1,266,072 of ~~the~~electric ~~state~~power and 1,086 MW of ~~New~~capacity ~~York~~in ~~filed~~2001. There ~~papers~~were no payments in 2000.Put ContractsAs a part of the MRA, the Company signed agreements with eight of the ~~PSC~~IPP ~~requesting~~Parties ~~that~~whereby the ~~amount~~IPP ofParties have an option to sell the ~~fee~~physical bedelivery ~~reduced~~of electric power to ~~approximately~~the $2Company at market prices.8 These ~~million~~agreements towould ~~reflect~~have ~~deletion~~been in effect until the earlier of the ~~stranded~~NYISO ~~costs~~meeting ~~claimed~~certain tovolume beand ~~unrelated~~capacity toconditions ~~local~~for ~~service.~~a Inconsecutive six-month period or until June 2008. Although the ~~November~~volume 28and capacity conditions have not yet been met in all of the contracts, ~~2001~~the ~~PSC~~Company ~~Order~~has negotiated ~~approving~~to terminate the ~~Merger~~requirement ~~Rate~~to ~~Plan,~~purchase electric power from the eight ~~PSC~~IPP ~~required~~Parties ~~that~~with ~~additional~~put ~~consideration~~agreements. Accordingly, ~~should~~there beis ~~made~~no ~~for~~further obligation ~~changes~~to purchase electric power under these contracts and information related to ~~Rule~~such 52contracts asis ~~originally~~not ~~identified~~included in ~~its~~the ~~earlier~~table ~~order~~above. The ~~Niagara~~Company ~~Mohawk~~did not ispay ~~unable~~anything toin ~~predict~~the year ended March 31, 2003 and the ~~outcome~~three months ended March 31, 2002, but paid approximately $1 million in 2001 and $46 million in 2000 for 13,844 MWh and 898,037 MWh, respectively, of ~~this~~electric ~~proceeding~~power atreceived ~~this~~as part ~~time.~~of these put agreements.While the ~~municipalization~~PPAs offor ~~Lakewood~~the ~~would~~fossil/hydro ~~not~~asset sales, ~~have~~which awere ~~material~~entered ~~impact~~into onas ~~Niagara~~an ~~Mohawk’s~~integral ~~results~~part of ~~operations~~the ~~and~~generation ~~financial~~sales, ~~position~~are above market, they are designed to help the ~~outcome~~Company meet the objectives of ~~this~~rate reduction ~~matter~~and ~~will~~price ~~likely~~cap ~~define~~commitments as well as meet expected demand as the “provider ~~methodology~~of tolast ~~determine~~resort” ~~exit~~as ~~fees~~outlined in the Power Choice agreement.At March 31, 2003, the Company had long-term contracts to purchase electric power from the following generation facilities owned by NYPA:

Alliance for Municipal Power

	Expiration	Purchased	Estimated	Estimated
	date of	capacity	annual	annual
Facility	contract	in MW	capacity cost	energy cost

Niagara - hydroelectric
project	2007	934	$ 31,596,000	$ 34,250,000
St. Lawrence - hydroelectric
project	2007	104	1,258,000	3,153,000

		1,038	$ 32,854,000	$ 37,403,000

The ~~Alliance~~purchase ~~for~~capacities ~~Municipal~~shown ~~Power~~above ~~(“AMP”)~~are isbased aon ~~group~~the contracts currently in effect. The estimated annual capacity costs are subject to price escalation and are exclusive of applicable energy charges. The total cost of purchases under these contracts, plus other miscellaneous NYPA purchases, was approximately, 20in ~~towns~~millions, $134, $35, $141, and ~~villages~~$144 infor ~~St.~~the ~~Lawrence~~year ended March 31, 2003, the three months ended March 31, 2002, and ~~Franklin~~the ~~counties~~calendar ~~pursuing~~years ~~municipalization~~2001 and 2000, respectively. The ~~AMP~~Company ~~appealed~~continues ~~the~~to ~~Commission~~have a contract with NYPA’s Fitzpatrick ~~orders~~nuclear ~~approving~~facility ~~Power~~to ~~Choice~~purchase ~~and~~for ~~Rule~~resale 52up to 46 MW of power for NYPA’s economic development customers.In addition to the contractual commitments described above, ~~which~~the ~~appeal~~Company ~~was~~entered ~~dismissed~~into bya four-year contract, expiring in June 2003, that gives it the ~~Supreme~~option ~~Court~~to ofbuy ~~Albany~~additional power ~~County.~~at ~~AMP~~market ~~filed~~prices anfrom ~~appeal~~the ofHuntley ~~this~~coal-fired ~~decision~~generation plant, ~~but~~now ~~failed~~owned by a new owner. If the Company needs any additional energy to ~~perfect~~meet its ~~appeal~~load ~~within~~it can purchase the ~~time~~electricity ~~limit~~from ~~specified~~other inIPPs, ~~New~~other ~~York~~utilities, other energy merchants or through the NYISO at market prices.Gas Supply, Storage and Pipeline Commitments: In connection with its regulated gas business, the Company has long-term commitments with a variety of suppliers and pipelines to purchase gas commodity, provide gas storage capability and transport gas commodity on interstate gas pipelines.The table below sets forth the Company’s ~~Civil~~estimated ~~Practice~~commitments ~~Laws~~at March 31, 2003, for the next five years, and ~~Rules~~thereafter.

At the PSC’s request, Niagara Mohawk provided AMP with stranded cost calculations under Rule 52 and Order No. 888. Niagara Mohawk estimated AMP’s total stranded cost estimate at $150 million under Rule 52 and $272 million under Order No. 888. On June 23, 1999, a representative of the AMP communities submitted a letter to the PSC disputing Niagara Mohawk’s exit fee calculations and requesting that the alternative dispute resolution procedures of Niagara Mohawk’s Power Choice Settlement be invoked to resolve that dispute. By letter dated August 10, 1999, the PSC directed Niagara Mohawk to meet with representatives of the AMP communities and an administrative law judge employed by the PSC. Thereafter, representatives of Niagara Mohawk and the AMP communities met on several occasions to exchange information and views on this subject, but no agreement has been reached.

Fiscal Year	(In thousands of dollars)
Ended		Gas Storage/
March 31,	Gas Supply	Pipeline

2004	$130,820	$61,562
2005	71,030	61,562
2006	71,030	9,314
2007	63,456	5,913
2008	-	5,913
2009-2013	-	22,417

OnWith ~~September~~respect 29to firm gas supply commitments, ~~2000~~the amounts are based upon volumes specified in the contracts giving consideration for the minimum take provisions. Commodity prices are based on New York Mercantile Exchange quotes and reservation charges, ~~AMP~~when applicable. Storage and pipeline capacity commitments’ amounts are based upon volumes specified in the contracts, and represent demand charges priced at current filed tariffs. At March 31, 2003, the Company’s firm gas supply commitments extend through October 2006, while the gas storage and transportation commitments extend through October 2012.Sale of Customer Receivables: The Company has established a ~~Petition~~single-purpose, ~~for~~financing subsidiary, NM Receivables LLC (“NMR”), whose business consists of the purchase and resale of an undivided ~~Expedited~~interest ~~Declaratory~~in ~~Order~~a ~~with~~designated pool of the ~~FERC.~~Company Incustomer ~~that~~receivables, including ~~petition~~accrued unbilled revenues. For receivables sold, ~~AMP~~the ~~urged~~Company has retained collection and administrative responsibilities as agent for the purchaser. As ~~FERC~~collections reduce previously sold undivided interests, new receivables are customarily sold. NMR has its own separate creditors which, upon liquidation of NMR, will be entitled to ~~nullify~~be satisfied out of its assets prior to any value becoming available to the ~~exit~~Company. The sale of receivables are in fee ~~provisions~~simple for a reasonably equivalent value and are not secured loans. Some receivables have been contributed in the form of ~~Niagara~~a ~~Mohawk~~capital contribution to NMR in fee simple for reasonably equivalent value, and all receivables transferred to NMR are assets owned by NMR in fee simple and are not available to pay the Company’s ~~Retail~~creditors.At ~~Tariff~~March on31, 2003 and 2002, receivables of $25 million and $0, respectively, had been sold by NMR to a ~~variety~~third party. The undivided interest in the designated pool of ~~grounds~~receivables is sold with limited recourse. The Inagreement provides for a formula based loss reserve pursuant to which additional customer receivables are assigned to the purchaser to protect against bad debts. To the extent actual loss experience of the pool receivables exceeds the loss reserve, the purchaser absorbs the excess. Concentrations of credit risk to the purchaser with respect to accounts receivable are limited due to the Company’s large, diverse customer base within its service territory. The Company generally does not require collateral (i.e. customer deposits).Environmental Contingencies: The public utility industry typically utilizes and/or generates in its operations a broad range of hazardous and potentially hazardous wastes and by-products. The Company believes it is handling identified wastes and by-products in a manner consistent with federal, state, and local requirements and has implemented an environmental audit program to identify any potential areas of concern and aid in compliance with such requirements. The Company is also currently conducting a program to investigate and remediate, as necessary, to meet current environmental standards, certain properties associated with former gas manufacturing and other properties which the Company has learned may be contaminated with industrial waste, as well as investigating identified industrial waste sites as to which it may be determined that the Company has contributed. The Company has also been advised that various federal, state, or local agencies believe certain properties require investigation and has prioritized the sites based on available information in order ~~dated~~to ~~January~~enhance 25the management of investigation and remediation, ~~2001~~if necessary.The Company is currently aware of 117 sites with which it may be associated, including 60, which are the ~~FERC~~Company-owned. With ~~dismissed~~respect ~~AMP~~to non-owned sites, the Company may be required to contribute some proportionate share of remedial costs. Although one party can, as a matter of law, be held liable for all of the remedial costs at a site, regardless of fault, in practice costs are usually allocated among Potentially Responsible Parties (“PRPs”). The Company has denied any responsibility at certain of these PRP sites and is contesting liability accordingly. At non-owned manufactured gas plant sites, the Company may bear full or partial responsibility for remedial costs.Investigations at each of the Company-owned sites are designed to (1) determine if environmental contamination problems exist; (2) if necessary, determine the appropriate remedial actions; and (3) where appropriate, identify other parties who should bear some or all of the cost of remediation. Legal action against such other parties will be initiated where appropriate. As site investigations are completed, the Company expects to determine site-specific remedial actions and to estimate the attendant costs for restoration. However, since investigations and regulatory reviews are ongoing for most sites, the estimated cost of remedial action is subject to change.Estimates of the cost of remediation and post-remedial monitoring are based upon a variety of factors, including identified or potential contaminants, location, size and use of the site, proximity to sensitive resources, status of regulatory investigation, and knowledge of activities at similarly situated sites. Actual expenditures are dependent upon the total cost of investigation and remediation and the ultimate determination of the Company’s ~~petition~~share ~~without~~of ~~prejudice~~responsibility for such costs, as well as the financial viability of other identified responsible parties since clean-up obligations are joint and several.As a consequence of site characterizations and assessments completed to ~~AMP~~date and negotiations with other PRPs or with the appropriate environmental regulatory agency, the Company has accrued a liability in the amount of $301 million, which is reflected in the Company’s ~~right~~Consolidated Balance Sheets at March 31, 2003. The potential high end of the range is presently estimated at approximately $530 million. The Company determines site liabilities through feasibility studies or engineering estimates, the Company’s estimated share of a PRP allocation, or, where no better estimate is available, the low end of a range of possible outcomes is used. In response to ~~raise~~an ~~any~~October 1999 request for information, the Company informed the New York Department of Environmental Conservation (“DEC”) of 24 additional former manufactured gas plant sites that it may be associated with, including three sites that are currently owned by the Company. The ~~issues~~Company ~~raised~~has ~~therein~~executed a voluntary clean-up order with the DEC for the investigation and, as required, the remediation of these additional sites. The Company has included amounts for the investigation and long term monitoring of these sites in the estimated liability. The Company is currently unable to estimate the costs to remediate these additional sites, since they primarily relate to non-owned sites that have been owned and operated by other parties, as well as by some former manufactured gas plant-related predecessor companies of the Company, and because they have not been subjected to site investigations.The Company has recorded a ~~proceeding~~regulatory ~~before~~asset representing the ~~PSC~~investigation, remediation and monitoring obligations to be recovered from ratepayers. The OnMerger ~~February~~Rate 23Plan provides for the continued application of deferral accounting for variations in spending from amounts provided in rates. As a result, ~~2001~~the Company does not believe that site investigation and remediation costs will have a material adverse effect on its results of operations or financial condition.Nuclear Contingencies: As of March 31, ~~AMP~~2003, ~~requested~~the ~~rehearing~~Company has a liability of ~~this~~$142 million in other regulatory and other liabilities for the disposal of nuclear fuel irradiated prior to 1983. In January 1983, the Nuclear Waste Policy Act of 1982 (the “Nuclear Waste Act”) established a cost of $.001 per KWh of net generation for current disposal of nuclear fuel and provides for a determination of the Company’s liability to the U.S. ~~Niagara~~Department ~~Mohawk~~of Energy (“DOE”) for the disposal of nuclear fuel irradiated prior to 1983. The Nuclear Waste Act also provides three payment options for liquidating such liability and the ~~PSC~~Company ~~both~~has ~~opposed~~elected to ~~this~~delay ~~request~~payment, with interest, until the year in which ~~was~~Constellation, ~~denied~~who purchased bythe Company’s nuclear assets, initially plans to ship irradiated fuel to an approved DOE disposal facility. Progress in developing the ~~FERC~~DOE facility has been slow and it is anticipated that the DOE facility will not be ready to accept deliveries until at least 2010.Plant Expenditures: The Company’s utility plant expenditures are estimated to be approximately $297 million in anfiscal ~~order~~2004. ~~dated~~At March 2631, ~~2001~~2003, substantial commitments had been made relative to future planned expenditures.Legal matters: Alliance for Municipal Power v. New York State Public Service CommissionOn February 17, 2003, the Alliance for Municipal Power (“AMP”) ~~did~~filed with the New York state court a petition for review of decisions by the New York State Public Service Commission (the “PSC”) that maintain the PSC’s established policy of using average distribution rates when calculating the exit fees that may be charged to municipalities that seek to leave the Niagara Mohawk system and establish their own municipal light departments. Changes in the methodology for the calculation of the exit fee are not ~~appeal~~likely ~~this~~to ~~order~~have ~~within~~a material effect on Niagara Mohawk’s financial statements. However, AMP’s petition for review also challenges the ~~period~~lawfulness ~~provided~~of byNiagara ~~law~~Mohawk’s collection of exit fees from departing municipalities, regardless of the methodology used to calculate those fees. If the court were to rule that Niagara Mohawk is not authorized to collect exit fees, and if the ~~FERC~~AMP communities proceeded with their plans to municipalize power, the Company could experience a significant shortfall of revenue. In addition, such a ruling could encourage other municipalities to consider municipalizing. The Company would seek to defer any lost revenue for eventual recovery from its remaining customers pursuant to the terms of its rate plan. Niagara Mohawk believes that it has strong defenses to AMP’s ~~order~~petition and is contesting the petition vigorously.New York State v. Niagara Mohawk Power Corp. et al. On January 10, 2002, New York State filed a civil action against the Company and NRG in ~~this~~federal district ~~case~~court isin ~~now~~Buffalo, ~~final~~New York, for alleged violations of the federal Clean Air Act and related state environmental laws at the Dunkirk and Huntley power plants, which the Company sold in 1999 to NRG and its affiliates (collectively, “NRG”). The State alleged, among other things, that between 1982 and 1999, the Company modified the two plants 55 times without obtaining proper preconstruction permits and implementing proper pollution equipment controls. The state sought, among other relief, statutory penalties under the Clean Air Act, which could have a maximum value of $25,000 to $27,500 per day per violation.

OnThe ~~August~~Company ~~24,~~and ~~2001~~NRG moved to dismiss the complaint on statute of limitations and other grounds in 2002, ~~AMP~~and ~~filed~~on aMarch ~~petition~~27, ~~with~~2003, the ~~PSC~~court ~~seeking~~granted the amotions ~~declaratory~~in ~~order~~part, ~~directing~~holding athat ~~hearing~~the toviolations ~~determine~~of the ~~stranded~~Clean ~~cost~~Air ~~obligations~~Act ~~owed~~prior ~~Niagara~~to November ~~Mohawk.~~1996 ~~The~~were ~~Hearing~~barred ~~Officer~~by isthe infederal ~~the~~five-year ~~process~~statute of ~~developing~~limitations, aand that ~~schedule,~~related ~~with~~state ~~input~~statutory ~~from~~violations prior to November 1999 were barred by the ~~parties~~state tothree-year ~~this~~statute ~~proceeding~~of limitations. This ~~Niagara~~eliminated ~~Mohawk~~the Company’s ispotential ~~unable~~exposure to ~~predict~~statutory ~~with~~daily ~~certainty~~penalties prior to these dates. At the ~~outcome~~same oftime, ~~this~~the ~~proceeding~~court preserved the State’s non-regulatory claims against the Company and dismissed NRG from the suit.

IfOn ~~the~~April ~~AMP~~25, ~~communities~~2003, ~~withdrew~~the ~~from~~State ~~Niagara~~filed ~~Mohawk’s~~a ~~system,~~motion ~~Niagara~~for ~~Mohawk~~leave ~~would~~to ~~experience~~amend athe complaint ~~potential~~to ~~revenue~~assert ~~loss~~new ofclaims ~~approximately~~against ~~one~~both ~~percent~~the ~~per~~Company ~~year.~~and ~~The~~NRG ~~impact~~for onunspecified amounts. Among ~~Niagara~~other ~~Mohawk’s~~things, ~~electric~~the ~~margin~~state is ~~considered~~seeking to bereassert ~~immaterial.~~daily ~~Suspension~~violations of orthe ~~renegotiation~~Clean ofAir Act going back to 1982, the ~~exit~~time ~~fee~~period ~~provisions~~covered ofby ~~Power~~its ~~Choice~~original complaint. On ~~could~~May ~~have~~30, a2003, ~~material~~the ~~adverse~~Company ~~effect~~filed onpapers ~~Niagara~~in ~~Mohawk~~opposition to the State’s ~~results~~petition. Oral ofargument ~~operations,~~has ~~financial~~been ~~condition,~~scheduled ~~and~~for ~~future~~July ~~cash~~2, ~~flows~~2003.

~~Griffiss~~Prior ~~Local~~to ~~Development~~the ~~Corporation~~commencement of the enforcement action, on July 13, 2001, the Company filed a declaratory judgment action in New York State court in Syracuse against NRG seeking a ruling that NRG is responsible for the costs of pollution controls and mitigation that might result from the State’s enforcement action. As a result of NRG’s voluntary bankruptcy petition, filed in New York federal court for bankruptcy on May 14, 2003, the Company’s declaratory judgment action is stayed.Niagara Mohawk Power Corp. v. Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C. The Company is engaged in collections litigation to recover bills for station service rendered to the owners of three power plants (the “Plants”), which the Company sold in 1999 to three affiliates of NRG: Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C. (collectively, the “Defendants”). According to the Company’s records, as of March 31, 2003, the Defendants owed the Company approximately $33 million. After suit was filed, the parties agreed to stay the litigation to permit the FERC to try to resolve the dispute.As noted above, NRG, the parent company to the Defendants, filed a voluntary bankruptcy petition in New York federal court for bankruptcy on May 14, 2003. The Company intends to seek approval from the bankruptcy court to move forward in its FERC proceeding. Any FERC decision would determine the Company’s ability to charge the Defendants for station service electricity post-bankruptcy, but the collection of the outstanding station service bills as of the bankruptcy filing date will be governed by the bankruptcy court proceedings.

NOTE J – DERIVATIVES AND HEDGING ACTIVITY

In the normal course of business, the Company is party to derivative financial instruments (derivatives) including indexed swap contracts, gas futures, call and put options, electricity swaps, and gas basis swaps that are principally used to manage commodity price risk associated with its natural gas and electric operations. These financial exposures are monitored and managed as an integral part of the Company’s overall financial risk-management policy. At the core of the policy is a condition that the Company will engage in risk management activities using commodity and financial markets only when it has a physical market exposure in terms and volumes consistent with its core business. The Company does not issue or intend to hold derivative instruments for speculative trading purposes. The Company adopted effective January 1, 2001, Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 requires derivatives to be reported at fair value as assets and liabilities on the balance sheet.
The Company has eight indexed swap contracts, expiring in June 2008 that resulted from the Master Restructuring Agreement (“MRA”), and three swap contracts, expiring in June and September 2003, from the sale of the Company’s Huntley, Dunkirk and Albany electric generating stations. These derivatives are not designated as hedging instruments and are covered by regulatory rulings that allow the gains and losses to be recorded as regulatory assets or regulatory liabilities. As of March 31, 2003 and 2002, the Company has recorded liabilities of $793.0 million and $653.9 million for these swap contracts, respectively, and has recorded regulatory assets of equal value. The asset and liability will be amortized over the remaining term of the swaps as nominal energy quantities are settled; however, the value of the unsettled contractual quantities will vary based upon market conditions.

InAt aMarch ~~petition for expedited declaratory ruling filed with the FERC on June 24~~31, ~~1999~~2003, ~~the~~Niagara ~~Griffiss~~Mohawk ~~Local~~projects ~~Development Corporation (“GLDC”) and the Oneida County Industrial Development Agency (“Oneida IDA”) sought an order declaring~~ that ~~purchases~~it ofwill ~~electricity~~make ~~from Niagara Mohawk by~~ the following ~~Air~~payments ~~Force~~in ~~Base~~connection ~~Conversion~~with ~~Agency~~its ~~and/or~~swap bycontracts ~~GLDC itself~~ for ~~use at~~ the ~~former~~fiscal ~~Griffiss~~years 2004 ~~Air~~through ~~Force~~2008 ~~Base~~and ~~(“the~~thereafter, ~~Base”) were wholesale sales~~ subject to ~~the~~changes jurisdiction of the FERC rather than retail sales subject to the jurisdiction of the PSC. In addition, GLDC and Oneida IDA also sought an order from the FERC asserting exclusive jurisdiction over any stranded cost obligation resulting from the change from retail to wholesale rates and a determination that Niagara Mohawk was not entitled to any stranded costs as a result of that change. Niagara Mohawk intervened in ~~this~~market ~~proceeding~~prices and indexing ~~opposed all relief requested by GLDC. The FERC has not yet acted on this Petition.~~provisions:

On July 19, 1999, GLDC and Oneida IDA filed an application with the PSC for a certificate of public convenience and necessity allowing them to furnish electric service to retail customers located on the Base, subject to light-handed regulation by the PSC. On October 1, 1999, Niagara Mohawk intervened in this PSC proceeding and stated that it was opposed to the issuance of the approvals requested by GLDC and Oneida IDA unless they agreed to pay an exit fee, which Niagara Mohawk estimated at $12 million. GLDC filed responsive testimony and calculated an exit fee of $180,000, and the PSC outlined an exit fee of approximately $7 million in its testimony. A substantial portion of the difference between the Niagara Mohawk estimate and the PSC estimate related to future anticipated load to be served by GLDC. GLDC and Oneida IDA refused to agree to these terms, and the PSC set that case for hearing before one of its administrative law judges.

	Projected
	Payment
Year Ended	(in thousands
March 31,	of dollars)

2004	$ 191,920
2005	148,073
2006	150,785
2007	141,311
2008	132,503
Thereafter	28,860
	$ 793,452

~~Shortly~~The ~~before~~Company ~~that~~uses ~~hearing~~New ~~was~~York ~~scheduled~~Mercantile toExchange ~~commence,~~(“NYMEX”) ~~Niagara~~gas futures ~~Mohawk~~and ~~entered~~gas ~~into~~basis aswaps ~~settlement~~to ~~agreement~~hedge ~~with~~gas ~~GLDC~~commodity ~~and~~components ~~Oneida~~of ~~IDA~~its indexed swap contracts. There ~~That~~were ~~settlement~~no ~~agreement~~open ~~ultimately~~basis ~~proved~~swaps ~~unworkable,~~at ~~due~~March to31, ~~the~~2003 ~~unavailability~~or of2002; however ~~certain~~basis ~~economic~~swaps ~~benefits~~were ~~from~~used during the ~~state~~fiscal ofyear. For ~~New~~the ~~York.~~twelve ~~The~~months ended ~~parties~~March ~~met~~31, ~~thereafter~~2003 ~~and~~the ~~have~~basis ~~recently~~swaps ~~executed~~resulted in a ~~new~~decrease ~~settlement~~to ~~agreement~~purchased ~~which~~power expense ~~would~~of ~~resolve~~$0.2 ~~all~~million. At ~~issues~~March in31, ~~this~~2003, ~~case.~~the ~~This~~Company ~~settlement~~recorded isa ~~conditioned~~deferred gain on ~~approval~~the byfutures ~~the~~contracts ~~PSC~~of ~~and~~$17.3 ~~acceptance~~million, offset by the ~~FERC~~balance ~~without~~sheet ~~material~~item “Derivative ~~modification~~Instruments” orfor ~~change,~~$ ~~which~~14.2 ~~has~~million ~~not~~with ~~yet~~the ~~been~~resulting ~~obtained~~$3.1 having ~~Niagara~~settled ~~Mohawk~~through ~~cannot~~cash ~~predict~~for the ~~outcome~~hedge month of ~~any~~April ~~proceedings~~2003. At ~~before~~March ~~the~~31, 2002 ~~PSC~~there orwere no open futures contracts. For the ~~FERC~~twelve ~~relating~~months ended March 31, 2003 settlement of NYMEX futures contracts resulted in a decrease to purchased ~~this~~power ~~agreement~~expense of $29.3 million.

Consistent with the Company’s commodity price risk management strategy, during the reporting periods the Company purchased NYMEX gas futures and used combination call and put options (collars) that meet the requirements for and are designated as cash flow hedging instruments in accordance with SFAS No. 133. There were no open positions in either NYMEX futures or collars at March 31, 2002. For NYMEX futures at March 31, 2003, the Company has recorded a deferred gain of $0.9 million. The deferred gain was offset by the balance sheet item “Derivative Instruments” for $0.9 million with a minimal amount having settled through “Cash” for the hedge month of April 2003. Call options at March 31, 2003 were in an asset position of $1.3 million with $1.1 million deferred in a regulatory liability and $0.2 million deferred in Accumulated Other Comprehensive Income net of deferred taxes. Put options at March 31, 2003 were in a liability position of $0.9 million with $0.9 million deferred in a regulatory asset and a nominal amount deferred in Accumulated Other Comprehensive Income net of deferred taxes. The gains and losses on the derivative that are deferred and reported in accumulated other comprehensive income will be reclassified as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. For the twelve months ended March 31, 2003, a net decrease of $10.0 million was recorded to gas purchases offset by a corresponding increase in the cost of a comparable amount of gas. The actual amounts to be recorded in earnings are dependent on future changes in the contract values, the majority of these deferred amounts will be reclassified to earnings within the next 12 months. A nominal amount of the hedging instruments extend into April 2004. There were no gains or losses recorded during the year from the discontinuance of gas futures and electricity swap cash flow hedges.

~~Niagara~~In ~~Mohawk~~the ~~has~~twelve ~~also~~months ~~prepared~~ended ~~exit~~March ~~fee~~31, ~~stranded~~2002, ~~cost~~fixed-for-floating ~~estimates~~swaps on electricity were utilized and resulted in a credit to purchased power of $0.4 million. None of these instruments were used during the year ended March 31, 2003. There were no open electric swaps at March 31, 2003 or 2002. In April 2003, the Company began utilizing NYMEX electric swap contracts to hedge electric purchases for ~~several~~the ~~other~~summer ~~municipalities~~2003. The ~~and~~Company ~~customers~~continues to evaluate the use of hedging instruments to manage the cost of electricity purchased.NOTE ~~Niagara~~K ~~Mohawk~~– isSTOCK ~~unable~~BASED COMPENSATIONUnder Holdings’ stock compensation plans prior to ~~predict~~the ~~whether~~merger, ~~these~~stock ~~other~~units ~~municipalities~~and stock orappreciation ~~customers~~rights ~~will~~(“SARs”) ~~pursue~~were agranted ~~withdrawal~~to ~~from~~officers, ~~Niagara~~key employees ~~Mohawk~~and directors. In addition, Holdings’s ~~system~~plans orpreviously allowed for the ~~amount~~grant of ~~stranded~~stock ~~costs~~options itto ~~may~~officers. The ~~receive~~table asbelow asets ~~result~~forth the activity under Holdings’ stock compensation plans for the years January 1, 2000 through March 31, 2003. On January 31, 2002, the acquisition of ~~any~~Holdings by ~~withdrawals~~National Grid was completed.

FERC Order 2000. In December 1999, the FERC issued Order 2000, which requires all public utilities that own, operate or control interstate electric transmission to file either a proposal for a Regional Transmission Organization (“RTO”) or an explanation of their reasons for not making such a proposal. Utilities not currently part of a FERC approved transmission entity were required to make their filings by October 15, 2000. Utilities, including Niagara Mohawk, who are part of a FERC approved transmission entity (Niagara Mohawk is a member of the NYISO), were required to make their filings by January 15, 2001.

				Options
				Wtd. Avg.
				Exercise
	SARs*	Units	Options	Price

Outstanding at December 31, 1999	2,852,562	864,994	247,375	$ 17.76
Granted	574,500	647,049	-
Exercised	(44,700)	(478,470)	-
Forfeited	(29,500)	(29,097)	(54,000)	17.94
Outstanding at December 31, 2000	3,352,862	1,004,476	193,375	17.71
Granted	-	662,281	-
Exercised	(190,611)	(336,423)	-
Forfeited	(5,347)	(21,337)	-	-
Outstanding at December 31, 2001	3,156,904	1,308,997	193,375	17.50
Granted	-	-	-
Exercised	(1,438,545)	(1,044,997)	(102,625)
Forfeited	(2,400)	(264,000)	(90,750)	17.50
Outstanding at January 31, 2002	1,715,959	-	-	-
Conversion of Holdings' stock to ADSs	(709,817)
Exercised	(46,257)
Outstanding at March 31, 2002	959,885	-	-	-
Exercised	(207,005)
Outstanding at March 31, 2003	752,880	-	-	-

* Note: The SARs related to Holdings' stock prior to the merger and National Grid Transco
American Depositary Shares subsequent to the merger on January 31, 2002.

The Company's SARs and stock units provided for the Onacceleration ~~January~~of 16vesting upon the occurrence of certain events relating to a change in control, ~~2001~~merger, sale of assets or liquidation of the Company. On ~~following~~January a31, ~~collaborative~~2002 ~~process~~outstanding ~~with~~Holdings SARs were converted to National Grid Transco plc (“NGT”) American Depositary Share (“ADS”) SARs. The SARs are payable in cash based on the ~~other~~increase ~~New~~in ~~York~~the ~~transmission~~ADS ~~owning~~price from ~~utilities~~a specified level. As such, ~~with~~for these awards, compensation expense is recognized based on the ~~staff~~value of Holdings’ stock price or NGT’s ADS price over the ~~NYISO~~vesting period of the award. Upon the closing of the merger, the units were paid, and ~~other~~each ~~New~~stock ~~York~~option ~~wholesale~~outstanding ~~market~~was cancelled and entitled ~~participants~~the holder to receive an amount in cash. Included in the Company’s results of operations for year ended March 31, ~~Niagara~~2003, ~~Mohawk~~the three months ended March 31, 2002, and the ~~other~~years ~~New~~ending ~~York~~December ~~transmission~~31, ~~owning~~2001 ~~utilities~~and 2000, is approximately $3 million, $21 million, $12 million, and ~~the~~$11 ~~NYISO~~million, respectively, ~~made~~related ato ~~joint~~these ~~filing~~plans.Since ~~with~~stock ~~the~~units ~~FERC~~and ~~describing~~SARs ~~how~~are payable in cash, the ~~NYISO~~accounting under APB No. 25 and SFAS No. 123 is the same. ~~generally~~Therefore, ~~compliant~~the ~~with~~pro ~~many~~forma disclosure of information regarding net income, as required by SFAS No. 123, related only to Holdings’ outstanding stock options, the ~~Order~~effect ~~2000~~of ~~requirements~~which is immaterial to the financial statements for the 30 day period ended January 30, 2002, and ~~specifying~~ the years ended 2001 and 2000. There ~~steps~~were ~~that~~no ~~will~~outstanding bestock ~~taken~~options subsequent to ~~achieve~~the ~~full~~closing ~~compliance~~of ~~with~~the merger.NOTE L – SEGMENTSThe Company’s reportable segments for the ~~remaining~~year ended March 31, 2003 are ~~requirements~~electricity-transmission, ofelectricity-distribution, ~~that~~and ~~Order~~gas. The ACompany ~~number~~is engaged principally in the business of ~~generators~~purchase, ~~marketers~~transmission, and ~~industrial~~distribution ~~customers~~of ~~subsequently~~electricity ~~intervened~~and the purchase, distribution, sale, and transportation of natural gas in ~~this~~New ~~proceeding~~York ~~requesting~~State. Certain information regarding the Company’s segments is set forth in the following table. General corporate expenses, property common to the various ~~forms~~segments, and depreciation of such ~~relief~~common ~~ranging~~property ~~from~~have been allocated to the segments based on labor or plant, using a ~~FERC~~percentage ~~order~~derived ~~requiring~~from ~~the~~total ~~NYISO~~labor or plant dollars charged directly to certain ~~merge~~operating ~~with~~expense ~~the~~accounts ~~New~~or certain plant accounts. Corporate assets ~~England~~consist ~~Independent~~primarily ~~System~~of ~~Operator~~other ~~(“ISO~~property ~~New~~and ~~England”)~~investments, cash, restricted cash, current deferred income taxes, and unamortized debt expense. ~~Pennsylvania~~For ~~Jersey~~periods ~~Maryland~~prior ~~independent~~to ~~system~~the ~~operator~~year ended March 31, 2003, the segment data presented is limited to electricity (~~“PJM”~~in total) and gas. Prior to the Company’s merger ~~modification~~with orNational ~~abolition~~Grid, ofthe ~~various~~electricity ~~provisions~~segment ofwas managed as a single operating unit, with a single bundled rate structure. Beginning in fiscal 2003, new mechanisms were put in place to capture the ~~NYISO~~separate financial information, including revenue, for electricity-transmission and electricity-distribution in the Company’s ~~Open~~detailed ~~Access~~accounting records to facilitate the new management ~~Transmission~~approach. These ~~Tariff~~mechanisms were not in place in prior periods. Additionally, prior to fiscal 2003 the Company was also engaged in the operation of electricity generation, further complicating the development of comparable segment information for the prior periods. As a result, presentation of pre-fiscal 2003 information on a basis fully comparable to the fiscal 2003 reportable segments is not possible, and any attempt to develop additional segment data would require undue time and effort in recalculating comparative amounts.

Because Order No. 2000 requires that RTOs have full filing rights under Section 205 of the Federal Power Act (“FPA”) with respect to their tariffs, Niagara Mohawk and the other New York Transmission Owners sought rehearing of that decision on the ground that participation in an RTO would strip those utilities of their statutory rights under the FPA. The FERC rejected this contention in an Order dated February 25, 2001, and Niagara Mohawk and the other New York Transmission Owners appealed those rulings to the United States Court of Appeals for the District of Columbia Circuit. On December 11, 2001, the United States Court of Appeals for the District of Columbia Circuit dismissed the New York Transmission Owners’ appeal of Order 2000 on the ground that those utilities were not aggrieved by anything in that order because the FERC had held in that order that participation in RTOs was “voluntary” and, hence, lacked standing to seek judicial review of that order. The court noted that the FERC had given each utility the choice of filing an RTO proposal or of making a filing explaining its reasons for not doing so, and that no party had demonstrated that any utility refusing to join an RTO would be punished for its failure to do so.

(Successor - in millions of dollars)
			Electric -	Electric -
			Transmission	Distribution	Gas	Corporate	Total

Year ended March 31, 2003
	Operating revenue		$ 248	$ 3,062	$ 709	$ -	$ 4,019
	Operating income before
		income taxes	85	437	68	-	590
	Depreciation and amortization		35	127	36	-	198
	Amortization of stranded costs		-	149	-	-	149

Goodwill
	Goodwill, at March 31, 2002		$ 304	$ 712	$ 215	$ -	$ 1,231
	Decrease in goodwill		(1)	(3)	(1)	-	(5)
	Goodwill, at March 31, 2003		$ 303	$ 709	$ 214	$ -	$ 1,226

March 31, 2003
	Total assets		$ 1,444	$ 8,780	$ 1,576	$ 444	$ 12,244

On July 12, 2001, FERC ruled that the NYISO and ISO New England did not satisfy the RTO requirements of Order 2000 for a variety of reasons, including lack of an adequate geographic scope. On July 24, 2001, the PSC announced its support of FERC’s process to establish a single RTO to run the daily power markets and oversee the flow of electricity in the Northeastern United States, citing both economic and system reliability benefits. In addition, the PSC noted its belief that the RTO approach would strengthen the reliability of the system, promote better transmission planning and result in efficient wholesale prices for electricity. In another order issued on July 12, 2001, the FERC provisionally certified PJM as an RTO, on the condition that it merge with the NYISO and ISO New England to achieve adequate geographic scope. To facilitate that merger, the FERC ordered the commencement of a mediation process to develop a plan that would achieve a single RTO for the Northeast region of the country utilizing the best practices from each of the existing Northeast ISOs.

(Successor - in millions of dollars)
			Electric	Gas	Corporate	Total

60 Day Period ended March 31, 2002
	Operating revenue		$ 540	$ 150	$ -	$ 690
	Operating income before
		income taxes	95	24	-	119
	Depreciation and amortization		27	6	-	33
	Amortization of Stranded Costs		24	-	-	24

March 31, 2002
	Total assets		$ 10,271	$ 1,422	$ 409	$ 12,102


(Predecessor - in millions of dollars)
			Electric	Gas	Corporate	Total

30 Day Period ended January 30, 2002
	Operating revenue		$ 283	$ 80	$ -	$ 363
	Operating income before
		income taxes	3	7	-	10
	Depreciation and amortization		14	3	-	17
	Amortization of Stranded Costs		41	-	-	41

This mediation process commenced in August 2001 and involved all entities involved in the three Northeast regions, as well as Canadian entities. The mediation process focused on developing a “best practices” approach and associated business plan to migrate the three ISOs into one Northeast RTO. The resulting business plan was submitted by the FERC ALJ to the Commission on September 17, 2001. Additionally, FERC issued a rulemaking addressing Standard Market Design regarding the buying and selling of power. The FERC requested in a December 2001 Order that all industry segments try to agree on a single standards organization that would establish national standards business practices for the wholesale electric industry. The FERC indicated that if the industry cannot reach agreement by March 15, 2002, the FERC will either choose such an organization itself or develop such standard business practices on its own. In January 2002, PJM Interconnection, together with the Midwest Independent Transmission System Operators, Inc., and the Southwest Power Pool, Inc. announced the formation of a Single Market Design Forum to identify the needs of market participants and promote efficiency in electricity markets. On January 29, 2002, the NYISO and ISO New England executed an agreement to develop a common electricity marketplace for their adjacent regions based on common market design and to evaluate the possibility of creating a northeast RTO, even though the geographic scope of such an RTO is still an open question.

(Predecessor - in millions of dollars)
			Electric	Gas	Corporate	Total

Three Months Ended March 31, 2001 (Unaudited)
	Operating revenue		$ 824	$ 356	$ -	$ 1,180
	Operating income before
		income taxes	114	43	-	157
	Depreciation and amortization		69	9	-	78
	Amortization of Stranded Costs		91	-	-	91


(Predecessor - in millions of dollars)
			Electric	Gas	Corporate	Total

Year ended December 31, 2001
	Operating revenue		$ 3,393	$ 722	$ -	$ 4,115
	Operating income before
		income taxes	223	135	-	358
	Depreciation and amortization		256	36	-	292
	Amortization of Stranded Costs		393	-	-	393


(Predecessor - in millions of dollars)
			Electric	Gas	Corporate	Total

Year ended December 31, 2000
	Operating revenue		$ 3,207	$ 659	$ -	$ 3,866
	Operating income before
		income taxes	358	73	-	431
	Depreciation and amortization		276	36	-	312
	Amortization of Stranded Costs		375	-	-	375

NOTE M – RESTRICTION ON COMMON DIVIDENDSThe ~~Niagara~~indenture ~~Mohawk~~securing ~~cannot~~the Company’s mortgage debt provides that retained ~~predict~~earnings ~~what~~shall ~~actions,~~be ifreserved ~~any,~~and held unavailable for the payment of dividends on common stock to the extent that expenditures for maintenance and repairs plus provisions for depreciation do not exceed 2.25 percent of depreciable property as defined therein. These provisions have never resulted in a restriction of the Company’s retained earnings.The Company is limited by the Merger Rate Plan and under FERC ~~will~~and ~~take~~Securities and Exchange Commission (“SEC”) orders with respect to the ~~business~~amount of dividends it ~~plan~~can ~~submitted~~make to itHoldings. The onCompany ~~September~~is ~~17,~~allowed ~~2001~~to make dividends in an amount up to the pre-merger retained earnings balance plus any earnings subsequent to the merger, ~~nor~~together ~~can~~with ~~Niagara~~other ~~Mohawk~~adjustments ~~predict~~that are authorized ~~whether~~under orthe ~~when~~Merger anRate ~~RTO~~Plan orand other ~~similar~~regulatory ~~entity~~orders.NOTE ~~may~~N be– SUBSEQUENT ~~established~~EVENTIn connection with an audit performed by PSC Staff, the Company has reached a settlement with the Staff that ~~would~~resolves all issues ~~include~~associated ~~Niagara~~with ~~Mohawk~~its pension and other postretirement benefit obligations for the period prior to the acquisition of the Company by National Grid. The settlement is subject to approval by the full New York State Public Service Commission. Among other things, the settlement covers the funding of the Company’s pension ~~service~~and ~~territory~~post-retirement orbenefit plans. Under the ~~financial~~settlement, ~~impacts~~the Company agreed to provide $100 million of tax-deductible funding by April 30, if2003 ~~any~~(which it funded in March 2003), and an additional $209 million, on a tax-deductible basis, by December 31, 2011. The Company will earn a rate of return of at least 6.60 percent on any portion of the $209 million that ~~may~~it ~~result~~funds before December 31, 2011, plus 80 percent of the amount by which the rate of return on the pension and post-retirement benefit funds exceeds 5.34 percent. This settlement resolves all PSC Staff audit issues related to the pre-acquisition period with the exception of certain gas deferrals and a Staff review of a pending Company compliance filing related to the sale of the Nine Mile Nuclear Station.NOTE O – QUARTERLY FINANCIAL DATA (UNAUDITED)Operating revenues, operating income, and net income (loss) by quarter from April 1, 2001 through March 31, 2003 are shown in the following ~~ultimate~~table. The ~~establishment~~Company believes it has included all adjustments necessary for a fair presentation of ~~any~~the ~~such~~results ~~RTO~~of oroperations ~~other~~for the quarters. Due to ~~similar~~the ~~entity~~seasonal nature of the regulated utility business, the annual amounts are not generated evenly by quarter during the year. The Company’s quarterly results of operations reflect the seasonal nature of its business, with peak electric loads in summer and winter periods. Gas sales peak in the winter.

FERC Order on Niagara Mohawk’s Transmission Rates with Sithe. Sithe/Independence Power Partners, LP (“Sithe”) had filed two separate complaints against Niagara Mohawk in 1995 and 1999. Both of these complaints challenged the transmission loss charges assessed by Niagara Mohawk. In its most recent complaint, Sithe also challenged Niagara Mohawk’s revenue requirements and sought a refund of approximately $65 million which it paid for certain interconnection facilities.

		In thousands of dollars
				Net
		Operating	Operating	Income
Quarter Ended		Revenues	Income	(Loss)
March 31,	2003(a)	$ 1,186,061	$ 133,586	$ 37,650
	2002(b)	1,052,327	98,602	9,705
December 31,	2002(a)	$ 967,807	$ 122,492	$ 37,551
	2001(c)	982,963	97,596	(1,852)
September 30,	2002(a)	$ 954,339	$ 119,264	$ 22,490
	2001(c)	1,007,839	34,736	11,848
June 30,	2002(a)	$ 911,243	$ 121,572	$ 28,180
	2001(c)	944,205	83,744	(24,648)

(a) Successor
(b) Includes both Successor and Predecessor financial data
(c) Predecessor

OnITEM June 29, 2001, Niagara Mohawk and Sithe negotiated and filed with the FERC a settlement that would have resolved all of the issues in both of these complaint proceedings for an amount that will not have a material adverse effect on Niagara Mohawk’s results of operations or financial condition9. CHANGES OnIN ~~October~~AND ~~11,~~DISAGREEMENTS ~~2001,~~WITH ~~FERC~~ACCOUNTANTS ~~issued~~ON anACCOUNTING ~~order~~AND ~~accepting~~FINANCIAL this settlement on the condition that Niagara Mohawk modify a provision of that settlement prohibiting the FERC from subsequently amending that agreement under any circumstances without the consent of both Sithe and Niagara Mohawk, unless the FERC found that change to be required by a compelling public interest. The FERC held that Sithe and Niagara Mohawk could bind themselves and the FERC to this high “public interest” standard with respect to disputes among themselves, but could not bind third parties to this standard. The Commission gave Niagara Mohawk 30 days to accept or reject this change to the settlement. DISCLOSURES

OnThe ~~November~~Company 9,has ~~2001, Niagara~~nothing ~~Mohawk~~to ~~and~~report ~~Sithe~~for ~~filed a revised settlement agreement with the FERC in compliance with the requirements of the FERC’s October 11, 2001 Order. While Niagara Mohawk believes that~~ this ~~revised settlement is in full compliance with the requirements of the FERC’s October 11, 2001 Order, Niagara Mohawk cannot predict the outcome of this proceeding at this time~~item.

~~Other~~PART Regulatory Restructuring Proceedings. The PSC continues to assess other functions in the regulated electric and gas business to lower consumer rates and increase customer choice. The PSC is considering opening competition to energy services and is re-examining the rates for the metering and billing functions already opened to competition. On January 13, 1999, the PSC adopted a set of Uniform Business Practices for Retail Access designed to streamline and make more uniform the manner in which the local utilities interact with natural gas and electricity marketers, energy services companies and customers who purchase energy in New York State’s evolving competitive market. III

~~Niagara~~ITEM ~~Mohawk’s results~~10. DIRECTORS ofAND ~~operations~~EXECUTIVE ~~has~~OFFICERS ~~not~~OF ~~been negatively impacted by the implementation of~~THE ~~the~~REGISTRANTThe ~~competitive~~following ~~metering~~table ~~and~~lists ~~billing functions due to~~ the ~~limited scope of the PSC~~Company’s ~~order on such functions and the use of long run avoided costs to~~executive ~~establish~~officers ~~back out credits against utility prices. The exposure could grow, however, as the rates for metering~~ and billing are re-examined, or other services are required to be opened to competition using embedded cost as a back out credit. The PSC has also instituted a separate track of its examination of provider of last resort issues to address the complete unbundling of electric and gas rates into components to facilitate expanded competition. Niagara Mohawk will continue to participate with the PSC and other parties as New York State moves forward with a competitive utility industry, but it cannot predict the outcome of the results and the impact on its Power Choice agreement or the Merger Rate Plan. directors:

OTHER FEDERAL AND STATE REGULATORY INITIATIVES

Name	Age	Position
William F. Edwards	46	President and Director
John G. Cochrane	45	Chief Financial Officer
Gary R. Jesmain	55	Senior Vice President, Business Services
Clement E. Nadeau	51	Senior Vice President, Operations, and Director
Kwong O. Nuey, Jr.	55	Vice President and Director
Anthony C. Pini	50	Senior Vice President, Customer Service, and Director
Steven W.Tasker	45	Vice President
Lawrence J. Reilly	47	General Counsel of National Grid USA
Joseph T. Ash, Jr.	54	Vice President, Gas Delivery
Edward A. Capomacchio	57	Controller
Michael E. Jesanis	46	Director

~~Gas~~Directors ~~Multi-Year~~are ~~Rate~~elected at the annual meeting of stockholders and ~~Restructuring~~hold office ~~Agreement.~~until ~~Niagara~~the ~~Mohawk~~next ~~filed~~annual meeting or a ~~three-year~~special ~~gas~~meeting ~~rate~~in lieu thereof, and ~~restructuring~~until ~~proposal~~their onsuccessors ~~March~~are ~~11,~~elected ~~1999,~~and inqualified. All ~~anticipation~~ of the ~~expiration~~directors ofwere ~~its~~elected ~~1996~~in ~~three-year~~2002. There ~~gas~~are ~~rate~~no ~~settlement~~family ~~agreement,~~relationships ~~which~~between ~~expired~~any onof ~~November~~the 1,directors ~~1999.~~and Onexecutive ~~July~~officers ~~19,~~listed ~~2000,~~in the ~~PSC~~table. There ~~approved~~are ~~the~~no ~~agreement~~arrangements ~~that had been negotiated~~or understandings between ~~Niagara~~any ~~Mohawk~~executive ~~and~~officer ~~the PSC Staff~~ and ~~became~~any ~~effective~~other onperson ~~August~~pursuant ~~1, 2000.~~to ~~The~~which ~~agreement~~he ~~includes~~was ~~the~~selected ~~following:~~ as an officer.

Mr. Edwards was elected President of the Company and Senior Vice President of National Grid USA effective January 31, 2002. Prior to that, he served as Senior Vice President and Chief Financial Officer of the Company from 1997 to 2002. He served as Senior Vice President and Chief Financial Officer of Niagara Mohawk Holdings, Inc. from 1999 to 2002. He also serves as a director of National Grid USA and Utilities Mutual Insurance Company.

•Mr. ACochrane ~~freeze~~was onelected ~~Niagara~~Chief ~~Mohawk~~Financial Officer effective August 1, 2002. He has served as National Grid USA’s ~~delivery~~Chief ~~rates~~Financial Officer ~~for~~since aJanuary ~~three-year,~~2001 ~~ten-month~~and ~~period,~~Senior ~~beginning~~Vice ~~November~~President 1since May 2002 and was Treasurer of National Grid USA (and its predecessor, ~~1999.~~New ~~This~~England ~~would~~Electric System) ~~align~~and ~~the~~of ~~expiration~~National Grid USA Service Company from 1998 to 2002. Mr. Cochrane was also Treasurer of ~~the~~Massachusetts ~~gas~~Electric ~~rate~~Company ~~agreement~~from ~~with~~1998 ~~the~~to ~~expiration~~2000 and of ~~the~~The ~~Power~~Narragansett ~~Choice~~Electric ~~agreement~~Company from 1993 to 2000. Mr. Jesmain has served as Senior Vice President, Business Services, since February 2002. From February 1996 to February 2002 he was Regional Manager, Central Region.

•Mr. ~~Commodity~~Nadeau ~~costs~~was ~~continue~~elected toSenior beVice ~~passed~~President ~~through~~of the Company effective January 31, 2002. Prior to ~~customers~~that, he served as Vice President-Electric Delivery beginning in 1998.

•Mr. ~~Niagara~~Nuey ~~Mohawk~~was ~~will~~elected ~~recover~~Vice ~~all~~President ~~potential~~and ~~stranded~~Chief ~~pipeline~~Information Officer ~~capacity~~of ~~costs~~National ~~that~~Grid ~~result~~USA Service Company effective January 31, 2002. He was the Vice President and Controller of National Grid USA Service Company from ~~customer~~2000 to ~~switching~~2002 ~~through~~and the ~~use~~Vice President and Director of Retail Information Services of the ~~contingency~~Company ~~reserve~~from ~~account~~1997-2000.Mr. Pini was elected Senior Vice President of the Company effective January 31, ~~which~~2002. Previously, he was President ~~established~~of byNEES Communications, Inc. from 1997 to 2002 and Vice President of Retail Customer Service of National Grid USA subsidiaries from 1993 to 1997.Mr. Tasker has served as Senior Vice President, Distribution Finance, and Treasurer since February 2002. He was Vice President and Controller from December 1998 to February 2002.Mr. Reilly has been 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. Ash has served as Vice President, Gas Delivery, since December 1998. From January 1996 to December 1998, he was Vice President, Purchasing and Support Services.Mr. Capomacchio was appointed Controller of the ~~previous~~Company ~~gas~~and ~~settlement~~Vice ~~agreement~~President and Controller of National Grid USA Service Company in January 2002. He has served as Controller of Massachusetts Electric Company, The Narragansett Electric Company, Nantucket Electric Company and Granite State Electric Company since May 2001. Mr. Capomacchio was Assistant Controller of the Service Company from 1998 to 2002. Mr. Jesanis has served as National Grid USA’s Executive Vice President and Chief Operating Officer of 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 Holdings, Inc.

•Section ~~Niagara Mohawk would give each customer who migrates to another gas supplier~~ 16(a) ~~merchant~~Beneficial ~~function~~Ownership backout credit, which reflects services Niagara Mohawk is no longer providing to that customer. Any stranded transition costs related to migration will be recoverable through the contingency reserve account.Reporting Compliance

•Section ~~A rate of return on common equity~~ 16(~~“ROE”~~a) ~~cap~~of ~~over~~ the ~~settlement~~Securities ~~period~~Exchange Act of 101934 ~~percent~~requires ~~with~~the Company’s aexecutive ~~50/50~~officers ~~sharing~~and ofdirectors, ~~excess~~and ~~earnings~~persons ~~above~~who ~~the~~own ~~cap~~more ifthan 10 ~~Niagara~~percent ~~Mohawk~~of ~~does~~a ~~not~~registered ~~achieve~~class ~~any~~ of the ~~incentive~~Company’s ~~linked~~equity ~~with~~securities, ~~customer~~to file ~~awareness~~reports ~~and~~with ~~understanding~~the ofSecurities ~~their~~and ~~ability~~Exchange toCommission ~~choose~~disclosing antheir ownership ~~alternate~~of ~~commodity~~stock ~~supplier~~in ~~or with~~ the ~~incentive~~Company ~~related~~and tochanges ~~customer~~in ~~migration~~such ~~levels~~ownership. To ~~Niagara~~the Company’s ~~Mohawk~~knowledge, ~~will~~based besolely ~~able~~on towritten ~~increase~~representations ~~its~~from reporting ~~earned~~persons, ~~ROE~~no ~~(up~~such toreports 12were ~~percent)~~required ~~without any sharing by achieving the incentive linked~~ to ~~customer~~be ~~awareness~~filed ~~and~~during ~~understanding of supplier choice and~~ the ~~incentive~~year ended ~~linked~~March to31, ~~migration levels~~2003.

~~The~~ITEM ~~Merger Rate Plan extends this settlement for an additional 16 months to December 2004~~11. EXECUTIVE COMPENSATION

~~RESULTS~~Summary OFCompensation ~~OPERATIONS~~TableThe following table sets forth the compensation paid or accrued for services rendered to Niagara Mohawk in fiscal year 2003, the transition period from January 1, 2002 to March 31, 2002 and the calendar years 2001 and 2000 by the president and the four most highly paid persons who were serving as executive officers on March 31, 2003 (the “Named Executive Officers”).

The following discussion presents the material changes in results of operations. Results of operations from 1999 through 2001 reflect the implementation of Power Choice and the sale of the generation assets at various times through that period. As a result of the closing of the MRA and the implementation of Power Choice effective September 1, 1998, reported earnings under Power Choice were substantially depressed as a result of the regulatory treatment of the MRA regulatory asset. The closing of the merger with National Grid on January 31, 2002 and the related push down and allocation of the purchase price and implementation of the Merger Rate Plan will effect the reported results of Niagara Mohawk prospectively. See “Merger Rate Plan” for further discussion of how the closing of the merger with National Grid will impact the future results on Niagara Mohawk. This discussion should also be read in conjunction with other financial and statistical information appearing elsewhere in this report.

Name and Principal Position	Year	Annual Compensation (a)			Long-Term Compensation		All Other Compen- sation ($)(d)
		Salary($)	Bonus($)(b)	Other Annual Compen-sation ($)(c)	Awards
		Salary($)	Bonus($)(b)	Other Annual Compen-sation ($)(c)	Restricted Stock Award(s) ($)	Securities Underlying Options/ SARs(#)
William F. Edwards President	2003 2002 (e) 2001 2000	399,993 99,665 379,994 331,663	224,396 41,141 222,716 142,816	6,010 0 4,785 0	0 0 354,000 425,938	56,206 0 0 25,000	1,823 3,882,601 600,267 80,699
Anthony C. Pini Senior Vice President Customer Service	2003	225,000	137,925	113,562	0	31,616	642
Clement E. Nadeau Senior Vice President Operations	2003	209,997	149,098	8,882	0	29,508	807
Joseph T. Ash, Jr. Vice President Gas Delivery	2003	193,297	76,932	6,911	0	21,723	895
Steven W. Tasker Senior Vice President Distribution Finance	2003 2002 (e) 2001 2000	179,998 43,599 162,656 160,004	86,399 17,412 64,681 49,087	8,281 1,308 1,994 0	0 0 106,200 130,938	20,234 0 0 7,000	296 95 171,198 46,260

~~Niagara~~(a) ~~Mohawk~~Includes ~~experienced~~deferred acompensation ~~loss~~ in ~~2001~~category and year earned. (b) The bonus figure represents cash bonuses and the fair market value of $1 unrestricted securities of National Grid Transco awarded under an incentive compensation plan and cash bonuses awarded under the all-employees goals program.3 ~~million~~(c) asIncludes ~~compared~~amounts toreimbursed afor ~~loss~~the payment of ~~$53~~taxes on certain noncash benefits and contributions to the incentive thrift plan that are not bonus contributions, including related deferred compensation plan match.7 ~~million~~For inMr. ~~2000~~Pini, also includes amounts associated with relocation ($104,161) and a ~~loss~~ ofnominal ~~$38~~miscellaneous cash award.9 ~~million~~(d) inIncludes ~~1999~~Company contributions to life insurance. (e) Information is for the transition period from January 1, 2002 to March 31, 2002.

~~Earnings~~Option ~~for~~Grants ~~2001~~in ~~were~~Last ~~positively~~Fiscal ~~impacted~~YearThe byfollowing table shows all stock option grants to the ~~following~~

Filing Compare · NIAGARA MOHAWK POWER CORP /NY/