SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

Amendment No. 1

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

For the fiscal year ended March 31, 2003

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

For the transition period___________to______________

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

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

Registrant	Title and Class

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

		3.90% Series
		3.60% Series

	Preferred Stock ($25 par value-cumulative):
	Adjustable Rate Series D

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K [ 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 common equity held by non-affiliates of the registrant: N/A

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

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.)

Explanatory Note

The Registrant is filing this amendment to include the Consolidated Statements of Cash Flows, which were inadvertently omitted from the Form 10-K filed on June 30, 2003. Other than the inclusion of the Consolidated Statements of Cash Flows, no other substantive changes have been made, and no attempt has been made to update any disclosures.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A. FINANCIAL STATEMENTS

Reports of Independent Auditors

Consolidated Statements of Operations, Consolidated Statements of Retained Earnings, and Consolidated Statements of Comprehensive Income (Loss) for the year ended March 31, 2003, the 60 day period ended March 31, 2002, the 30 day period ended January 30, 2002, and for the years ended December 31, 2001 and 2000

Consolidated Balance Sheets at March 31, 2003 and 2002

Consolidated Statements of Cash Flows for the year ended March 31, 2003, the 60 day period ended March 31, 2002, the 30 day period ended January 30, 2002, and the years ended December 31, 2001 and 2000

Notes to Consolidated Financial Statements

REPORT OF INDEPENDENT AUDITORS

To the Stockholders and Board of Directors of
Niagara Mohawk Power Corporation:

In our opinion, 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 Power Corporation and its subsidiaries at March 31, 2003 and 2002, and the results of their operations and 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 express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP

Boston, Massachusetts
May 7, 2003, except for the Legal Matters
section of Note I, as to which the date is May 30, 2003

REPORT OF INDEPENDENT AUDITORS

To the Stockholders and Board of Directors of
Niagara 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 30, 2002 and for each of the two years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP

Boston, Massachusetts
May 14, 2002

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)

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

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

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

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 accompanying notes are an integral part of these financial statements.

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flows

	Year	60 Day Period	30 Day Period	Three months
	ended	ended	ended	ended	Year ended December 31,
	March 31,2003	March 31,2002	January 30, 2002	March 31,2001	2001	2000
	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)	(Predecessor)
(in thousands of dollars)				(Unaudited)
Cash flows from operating activities:
Net income (loss)	$ 125,871	$ 30,646	$ (20,941)	$ 34,010	$ 19,358	$ (27,646)
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
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
Amortization of nuclear fuel	-	-	-	7,203	23,095	29,379
Change in restricted cash	(17,268)	14,261	6,402	(205)	(17,798)	(2,268)
Disallowed nuclear investment costs	-	-	-	-	123,000	-
Provision for deferred income taxes	123,950	50,814	3,024	9,639	(8,774)	(24,614)
Reversal of deferred nuclear investment tax credits	-	-	-	-	(79,711)	-
Changes in current operating assets and liabilities:
Net accounts receivable (net of changes in accounts
receivable sold)	(15,493)	(139,062)	(31,677)	(32,079)	1,153	(54,930)
Materials and supplies	(377)	30,302	21,538	47,114	(8,571)	(10,749)
Prepaid taxes	(73,279)	17,218	(28,190)	(17,570)	(2,702)	15,243
Accounts payable and accrued expenses	143,015	(27,981)	34,261	(138,117)	(198,742)	169,692
Accrued interest and taxes	(2,588)	28,979	264	19,599	(13,943)	33,800
Change in merger rate plan stranded costs	(24,115)	(17,224)	(7,095)	11,781	48,249	36,132
Deferral of MRA interest rate savings	11,461	2,184	1,092	4,229	15,009	20,469
Changes in other assets and liabilities, net	(23,800)	(70,358)	67,334	(18,648)	(36,708)	37,730
Net cash provided by (used in) operating activities	595,045	(23,811)	103,594	95,797	548,275	909,528
Cash flows from investing activities:
Construction additions	(245,001)	(25,126)	(13,459)	(52,535)	(249,430)	(231,892)
Nuclear fuel	-	-	-	(2,304)	(3,822)	(41,938)
Less: Allowance for other funds used during construction	187	167	136	798	2,296	2,450
Acquisition of utility plant	(244,814)	(24,959)	(13,323)	(54,041)	(250,956)	(271,380)
Proceeds from the sale of generation assets (payment of notes receivable for the year ended March 31, 2003)	249,799	-	-	83,838	353,785	47,500
Other investments	1,256	(3,176)	18,368	(16,261)	(33,793)	(71,983)
Other	(17,678)	15,357	(22,839)	752	(14,368)	6,713
Net cash provided by (used in) investing activities	(11,437)	(12,778)	(17,794)	14,288	54,668	(289,150)
Cash flows from financing activities:
Proceeds from long-term debt	500,000	-	-	-	534,152	260,000
Reductions of preferred stock	(2,131)	(390,289)	-	-	(3,050)	(7,620)
Reductions in long-term debt	(668,675)	(131,174)	(1,050)	(226,050)	(916,746)	(653,086)
Net change in short-term debt	(221,000)	419,000	-	115,000	(110,000)	110,000
Preferred dividends paid	(5,568)	-	(7,611)	(7,758)	(30,850)	(31,437)
Common stock dividend paid to Holdings (including a
return of capital of $86.1million for fiscal year 2003)	(150,000)	-	-	-	(37,160)	(46,132)
Repurchase of Holdings' common stock	-	-	-	-	-	(250,026)
Other	(16,078)	(2,391)	(23,048)	3,558	(8,179)	(1,041)
Net cash used in financing activities	(563,452)	(104,854)	(31,709)	(115,250)	(571,833)	(619,342)
Net increase (decrease) in cash and cash equivalents	20,156	(141,443)	54,091	(5,165)	31,110	1,036
Cash and cash equivalents at beginning of period	9,882	151,325	97,234	66,123	66,124	65,088
Cash and cash equivalents at end of period	$ 30,038	$ 9,882	$ 151,325	$ 60,958	$ 97,234	$ 66,124
Supplemental disclosures of cash flow information:
Interest paid	$ 21,821	$ 27,245	$ 23,647	$ 70,746	$ 373,100	$ 367,297
Income taxes paid	$ 34,799	$ -	$ -	$ 7	$ 51	$ 14,416

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

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE A – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation: Niagara Mohawk Power Corporation (the “Company”) is subject to regulation by the New York State Public Service Commission (“PSC”) and the 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 the 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 closing of the merger with National Grid USA (“National Grid”) and the related 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 assets at various times during 1999 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, such that certain individual line items are net of the effects of the sales.

Acquisition by National Grid: On January 31, 2002, the Company was acquired by National Grid for approximately $3 billion in cash and American Depositary 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 January 31, 2002. Information relating to all “predecessor” periods prior to the acquisition is presented 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 first 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 performance of the annual goodwill impairment test. The result of the annual analysis determined that no adjustment to the goodwill carrying value was required.

Use of Estimates: 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:

		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

The above amounts include capitalized interest for generation of $0.8 million and $1.7 million for calendar years ending December 31, 2001 and 2000, respectively. There was no capitalized interest for generation in 2003 and 2002.

Depreciation: For accounting and regulatory purposes, the Company’s depreciation is computed on the straight-line basis using the average service lives for all other classes. The Company performs depreciation studies to determine service lives of classes of property and adjusts the depreciation rates when necessary.

The weighted average service life, in years, for each asset category is presented in the table below:

		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 unbilled revenues included in accounts receivable at both March 31, 2003 and 2002 was approximately $132 million.

In 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 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 January 31, 2002.

The PSC approved a multi-year gas rate settlement agreement (ending December 2004) on July 19, 2000 that includes a provision for the continuation of a full gas cost collection mechanism, effective August 1, 2000. This gas cost collection mechanism was originally reinstated in an interim agreement 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 assets that were sold were taken into income in accordance with IRS rules. Regulated federal and state income taxes are recorded under the provisions of SFAS No. 109. Tax returns for Holdings and its 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, Holdings and 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 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 $6 million for the year ended March 31, 2003 and 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, “Accounting 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 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 replacement of Financial Accounting Standards Board (“FASB”) Statement 125” in 2001. The Company’s program for selling its accounts receivable meets the requirements outlined in SFAS No. 140 for recognition and accounting as a sale transaction. As a result, the adoption of this new standard did not have an impact on the reported financial information 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 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.

Reclassifications: Certain amounts from prior years have been reclassified on the accompanying Consolidated Financial Statements to conform to the 2003 presentation.

NOTE B – RATE AND REGULATORY ISSUES

The 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 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.

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 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 due to 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 accordance 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)

	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

NOTE D – PREFERRED STOCK

The Company has certain issues of non-participating preferred stock, which provide for redemption at the option of the Company, as shown in the table below. From time to time the Company repurchases shares of its preferred stock when it is approached on behalf of its shareholders.

					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.

NOTE E – LONG-TERM DEBT

Long-term debt consisted of the following:

$ 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

* Tax-exempt pollution control related issues

Several series of First Mortgage Bonds and Promissory Notes were issued to secure a like amount of tax-exempt revenue bonds issued by the New York State Energy Research and Development Authority (“NYSERDA”). Approximately $414 million of such securities bear interest at a daily adjustable interest rate (with an option to convert to other rates, including a fixed interest rate which would require the Company to issue First Mortgage Bonds to secure the debt) which averaged 1.36 percent for the year ended March 31, 2003, 1.12 percent for the three months ended March 31, 2002, 2.50 percent for 2001, and 4.06 percent for 2000 and are supported by bank direct pay letters of credit. Pursuant to agreements between NYSERDA and the Company, proceeds from such issues were used for the purpose of financing the construction of certain pollution control facilities at the Company’s generation facilities or to refund outstanding tax-exempt bonds and notes (see Note F).

On May 1, 2003, the Company completed the restructuring of $414 million of variable rate tax exempt bonds. The bonds are currently in the auction rate mode, which allowed the Company to terminate the $424 million of letter of credit facilities that were in place to provide liquidity support for principal and interest while the bonds were in a variable rate mode.

The aggregate maturities of long-term debt for the five years subsequent to March 31, 2003, excluding capital leases, in millions, are approximately $612, $533, $550, $279 and $200, respectively. The current portion of capital lease obligations is reflected in the other current liabilities line item on the Consolidated Balance Sheet and was approximately $1.0 million and $3.4 million at March 31, 2003 and 2002, respectively. The non-current portion of capital lease obligations is reflected in the other regulatory and other liabilities line item on the Consolidated Balance Sheet and was approximately $6 million and $7 million at March 31, 2003 and 2002, respectively.

At March 31, 2003, the Company's long-term debt had a fair value of approximately $4.4 billion. The fair market value of the Company’s long-term debt was estimated based on the quoted prices for similar issues or on the current rates offered to the Company for debt of the same remaining maturity.

Early Extinguishment of Debt

During the year ended March 31, 2003, the three months ended March 31, 2002, and the year ended December 31, 2000, the Company defeased or redeemed approximately $122 million, $119 million, and $95 million, respectively, in long-term debt prior to its scheduled maturity.

On May 1, 2003, the Company redeemed early $170 million of First Mortgage Bonds. The funds provided for this redemption came from available cash within the National Grid USA Money Pool.

Losses resulting from the early redemption of debt are deferred and amortized as interest expense ratably over the lives of the related issues in accordance with PSC directives (see Note B).

NOTE F – BANK CREDIT ARRANGEMENTS

The Company had short-term debt outstanding of $198 million and $419 million at March 31, 2003 and 2002, respectively, from the inter-company money pool. The Company has regulatory approval from the Securities and Exchange Commission, under the Public Utility Holding Company Act of 1935, to issue up to $1 billion of short-term debt. National Grid USA and certain subsidiaries, including the Company, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies that invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice.

The Company had a senior bank facility agreement that provided the Company with $424 million for letters of credit with a three-year term. The letter of credit facility provided credit support for the Company’s adjustable rate pollution control revenue bonds issued through the New York State Energy Research and Development Authority, discussed in Note E. At March 31, 2003, the Company had no loans outstanding under the credit facility. Subsequent to March 31, 2003, the Company converted its daily adjustable rate pollution control revenue bond program to an auction rate mode on May 1, 2003 and terminated the letter of credit facility.

NOTE G – FEDERAL, STATE AND FOREIGN INCOME TAXES

Following is a summary of the components of federal and state income tax and 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:

		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)

Reconciliation between federal income taxes and the tax computed at prevailing U.S. statutory rate on income before income taxes:

			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)

(a) Includes Carrying Charges (Interest Expense) imposed by the PSC.

(b) Deferred investment tax credits of $79.7 million and $0.8 million related to the generation assets that have been sold have been taken into income in 2001 and 2000, respectively, in accordance with IRS rules.
The deferred tax liabilities (assets) were comprised of the following:

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)

In December 1998, the Company received a ruling from the IRS which provided that the amount of cash and the value of common stock that was paid by the Company to the subject terminated IPP Parties was deductible in 1998 which resulted in the Company not paying any regular federal income taxes for 1998, and further generated a substantial net operating loss for federal income tax purposes. The Company carried back a portion of the unused NOL to the years 1996 and 1997, and also for the years 1988 through 1990, which resulted in federal income tax refunds of $135 million that were received in January 1999. As a result of the merger with National Grid, the Company is now part of the consolidated tax return filing group of National Grid General Partnership (the parent company, 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 $1.568 billion. National Grid’s ability to utilize the NOL carryforward generated as a result of the MRA and the utilization of alternative minimum tax credits is affected by the rules of Section 382 of the Internal Revenue Code.

NOTE H – PENSION AND OTHER RETIREMENT PLANS

The Company has a non-contributory defined benefit pension plan covering substantially all employees. The plan includes a cash balance benefit in which the participant has an account to which amounts are credited based on qualifying compensation and with interest determined annually based on the average annual 30-year Treasury bond yield. Supplemental non-qualified, non-contributory executive retirement programs provide additional defined pension benefits for certain executives. In addition, the Company provides 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:

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 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 the merger with National Grid, the Company revalued its assets and liabilities to their fair value in accordance with purchase accounting. This revaluation resulted in an increase to the Company’s pension and postretirement benefit 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:

(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

For the year ended March 31, 2003, the Company had a net settlement loss of $29.5 million relating to normal lump-sum distributions and the spin-off of the assets and liabilities related to the sale of NM Energy. For the 60 day period ended March 31, 2002, the Company had a net settlement gain of $16.7 million related to the sale of its nuclear assets. In 2001, the Company experienced a net curtailment/settlement loss of $31.9 million due to the employee transfers associated with the sale of the nuclear assets and change of control payments under 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 plant ownership and $14.7 million was charged to expense.

The non-qualified executive pension plan has no plan assets due to the nature of 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 components of the net annual benefit costs.

	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

(1) A portion of the benefit costs relates to construction labor, and accordingly, is allocated to construction projects.

		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

The assumed health cost trend rates decline to five percent in 2008 and remain at that level thereafter. The assumed health cost trend rates can have a significant effect on the amounts reported for the health care plans.

A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	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)

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 CONTINGENCIES

Commodity 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 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 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

* MW value represents the average annual quantity of purchased capacity

** Does not include puts (see below)

PURPA Contracts
Under the requirements of the Public Utilities Regulatory Policies Act of 1978, as amended (“PURPA”), the Company is required to purchase power generated by IPPs, as defined therein. The Company has 104 PPAs with 112 IPP facilities, amounting to approximately 505 MW of capacity at March 31, 2003. All of this capacity amount is considered firm and excludes PPAs that provide energy only. The table above includes the estimated payments for fixed costs (capacity) and variable costs (capacity, energy and related taxes) that the Company estimates it will be obligated to make under these 104 IPP contracts, excluding the put contracts (see below) and the financial obligation under the swap contracts. The payments to the IPPs are subject to the tested capacity and availability of the facilities, scheduling and price escalation. These payments have been significantly reduced by the 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 with an IPP, 2) a contract entered into along with the sale of the Oswego generation assets as discussed further below, and 3) the contract entered into along with the sale of the hydroelectric generation assets as discussed further below. With respect to the IPP contract, the Company is required to make capacity payments, including payments when the facility is not operating but available for service. The terms of this contract allow the Company to schedule energy deliveries and then pay for the 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 $416 million in the year ended March 31, 2003, the three months ended March 31, 2002, and the years end December 31, 2001 and 2000 for 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 Contracts
As 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

The table above 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 Company entered into PPAs to purchase 90 percent 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 8 years (Unit 1) and 10 years (Unit 2). The Company pays only for delivered output from the units. Upon the expiration of the PPA for Unit 2, there is a revenue sharing agreement whereby the Company is entitled to future payments from Constellation over a ten-year period if electric energy and capacity market prices exceed certain amounts during the ten-year sharing period. The Company would not be required to buy energy from Constellation, LLC under the revenue sharing agreement. Purchases under the nuclear PPAs began in November 2001. The Company paid approximately $269 million for 7,390,000 MWh of electric power and 985 MW of capacity in the year ended March 31, 2003, $61 million for 1,946,000 MWh of electric power and 1,086 MW of capacity in the three months ended March 31, 2002, and $38 million for 1,266,072 of electric power and 1,086 MW of capacity in 2001. There were no payments in 2000.

Put Contracts
As a part of the MRA, the Company signed agreements with eight of the IPP Parties whereby the IPP Parties have an option to sell the physical delivery of electric power to the Company at market prices. These agreements would have been in effect until the earlier of the NYISO meeting certain volume and capacity conditions for a consecutive six-month period or until June 2008. Although the volume and capacity conditions have not yet been met in all of the contracts, the Company has negotiated to terminate the requirement to purchase electric power from the eight IPP Parties with put agreements. Accordingly, there is no further obligation to purchase electric power under these contracts and information related to such contracts is not included in the table above. The Company did not pay anything in the year ended March 31, 2003 and the 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 electric power received as part of these put agreements.

While the PPAs for the fossil/hydro asset sales, which were entered into as an integral part of the generation sales, are above market, they are designed to help the Company meet the objectives of rate reduction and price cap commitments as well as meet expected demand as the “provider of last resort” as 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:

	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 purchase capacities shown above are based on 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, in millions, $134, $35, $141, and $144 for the year ended March 31, 2003, the three months ended March 31, 2002, and the calendar years 2001 and 2000, respectively. The Company continues to have a contract with NYPA’s Fitzpatrick nuclear facility to purchase for resale up to 46 MW of power for NYPA’s economic development customers.

In addition to the contractual commitments described above, the Company entered into a four-year contract, expiring in June 2003, that gives it the option to buy additional power at market prices from the Huntley coal-fired generation plant, now owned by a new owner. If the Company needs any additional energy to meet its load it can purchase the electricity from other IPPs, other 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 estimated commitments at March 31, 2003, for the next five years, and thereafter.

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

With respect to firm gas supply commitments, 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, 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 single-purpose, financing subsidiary, NM Receivables LLC (“NMR”), whose business consists of the purchase and resale of an undivided interest in a designated pool of the Company customer receivables, including accrued unbilled revenues. For receivables sold, the Company has retained collection and administrative responsibilities as agent for the purchaser. As 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 be satisfied out of its assets prior to any value becoming available to the Company. The sales of receivables are in fee simple for a reasonably equivalent value and are not secured loans. Some receivables have been contributed in the form of a 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 creditors.

At March 31, 2003 and 2002, receivables of $25 million and $0, respectively, had been sold by NMR to a third party. The undivided interest in the designated pool of receivables is sold with limited recourse. The agreement 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 to enhance the management of investigation and remediation, if necessary.

The Company is currently aware of 117 sites with which it may be associated, including 60 which are Company-owned. With respect 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 share of 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 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 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 an 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 Company has 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 regulatory asset representing the investigation, remediation and monitoring obligations to be recovered from ratepayers. The Merger Rate Plan provides for the continued application of deferral accounting for variations in spending from amounts provided in rates. As a result, 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, 2003, the Company has a liability of $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. Department 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 Company has elected to delay payment, with interest, until the year in which Constellation, which purchased the Company’s nuclear assets, initially plans to ship irradiated fuel to an approved DOE disposal facility. Progress in developing the 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 fiscal 2004. At March 31, 2003, substantial commitments had been made relative to future planned expenditures.

Legal matters:
Alliance for Municipal Power v. New York State Public Service Commission
On February 17, 2003, the Alliance for Municipal Power (“AMP”) 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 likely to have a material effect on Niagara Mohawk’s financial statements. However, AMP’s petition for review also challenges the lawfulness of Niagara 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 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 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 federal district court in Buffalo, 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.

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 November 1996 were barred by the federal five-year statute of limitations, and that related state statutory violations prior to November 1999 were barred by the state three-year statute of limitations. This eliminated the Company’s potential exposure to statutory daily penalties prior to these dates. At the same time, the court preserved the State’s non-regulatory claims against the Company and dismissed NRG from the suit.

On April 25, 2003, the State filed a motion for leave to amend the complaint to assert new claims against both the Company and NRG for unspecified amounts. Among other things, the state is seeking to reassert daily violations of the Clean Air Act going back to 1982, the time period covered by its original complaint. On May 30, 2003, the Company filed papers in opposition to the State’s petition. Oral argument has been scheduled for July 2, 2003.

Prior to the 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.

At March 31, 2003, Niagara Mohawk projects that it will make the following payments in connection with its swap contracts for the fiscal years 2004 through 2008 and thereafter, subject to changes in market prices and indexing provisions:

	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

The Company uses New York Mercantile Exchange (“NYMEX”) gas futures and gas basis swaps to hedge gas commodity components of its indexed swap contracts. There were no open basis swaps at March 31, 2003 or 2002; however basis swaps were used during the fiscal year. For the twelve months ended March 31, 2003 the basis swaps resulted in a decrease to purchased power expense of $0.2 million. At March 31, 2003, the Company recorded a deferred gain on the futures contracts of $17.3 million, offset by the balance sheet item “Derivative Instruments” for $14.2 million with the resulting $3.1 having settled through cash for the hedge month of April 2003. At March 31, 2002 there were no open futures contracts. For the twelve months ended March 31, 2003 settlement of NYMEX futures contracts resulted in a decrease to purchased power 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.

In the twelve months ended March 31, 2002, fixed-for-floating 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 the summer 2003. The Company continues to evaluate the use of hedging instruments to manage the cost of electricity purchased.

NOTE K – STOCK BASED COMPENSATION

Under Holdings’ stock compensation plans prior to the merger, stock units and stock appreciation rights (“SARs”) were granted to officers, key employees and directors. In addition, Holdings’ plans previously allowed for the grant of stock options to officers. The table below sets 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 Holdings by National Grid was completed.

				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 acceleration of vesting upon the occurrence of certain events relating to a change in control, merger, sale of assets or liquidation of the Company. On January 31, 2002 outstanding Holdings SARs were converted to National Grid Transco plc (“NGT”) American Depositary Share (“ADS”) SARs. The SARs are payable in cash based on the increase in the ADS price from a specified level. As such, for these awards, compensation expense is recognized based on the value of Holdings’ stock price or NGT’s ADS price over the vesting period of the award. Upon the closing of the merger, the units were paid, and each stock option outstanding was cancelled and entitled the holder to receive an amount in cash.

Included in the Company’s results of operations for year ended March 31, 2003, the three months ended March 31, 2002, and the years ending December 31, 2001 and 2000, is approximately $3 million, $21 million, $12 million, and $11 million, respectively, related to these plans.

Since stock units and SARs are payable in cash, the accounting under APB No. 25 and SFAS No. 123 is the same. Therefore, the pro forma disclosure of information regarding net income, as required by SFAS No. 123, related only to Holdings’ outstanding stock options, the effect of which is immaterial to the financial statements for the 30 day period ended January 30, 2002, and the years ended 2001 and 2000. There were no outstanding stock options subsequent to the closing of the merger.

NOTE L – SEGMENTS

The Company’s reportable segments for the year ended March 31, 2003 are electricity-transmission, electricity-distribution, and gas. The Company is engaged principally in the business of purchase, transmission, and distribution of electricity and the purchase, distribution, sale, and transportation of natural gas in New York State. Certain information regarding the Company’s segments is set forth in the following table. General corporate expenses, property common to the various segments, and depreciation of such common property have been allocated to the segments based on labor or plant, using a percentage derived from total labor or plant dollars charged directly to certain operating expense accounts or certain plant accounts. Corporate assets consist primarily of other property and investments, cash, restricted cash, current deferred income taxes, and unamortized debt expense.

For periods prior to the year ended March 31, 2003, the segment data presented is limited to electricity (in total) and gas. Prior to the Company’s merger with National Grid, the electricity segment was 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 separate financial information, including revenue, for electricity-transmission and electricity-distribution in the Company’s detailed accounting records to facilitate the new management approach. These 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.

(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

(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

(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 DIVIDENDS

The indenture securing the Company’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. 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 and Securities and Exchange Commission (“SEC”) orders with respect to the amount of dividends it can make to Holdings. The Company is allowed to make dividends in an amount up to the pre-merger retained earnings balance plus any earnings subsequent to the merger, together with other adjustments that are authorized under the Merger Rate Plan and other regulatory orders.

NOTE N – SUBSEQUENT EVENT

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.

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 table. The Company believes it has included all adjustments necessary for a fair presentation of the results of operations for the quarters. Due to the 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.

		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

SIGNATURES

Pursuant to the Requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	NIAGARA MOHAWK POWER
	CORPORATION


	By: /s/ William F. Edwards
	William F. Edwards
	President and Chief Executive Officer

Date: July 3, 2003

CERTIFICATIONS

Certification of Principal Executive Officer

I, William F. Edwards, certify that:

1. I have reviewed this amendment to annual report on Form 10-K of Niagara Mohawk Power Corporation (the “Report”);

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

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

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

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

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

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

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

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

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

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

Date: July 3, 2003	/s/ William F. Edwards
	William F. Edwards
	President and Chief Executive Officer

Certification of Principal Financial Officer

I, John G. Cochrane, certify that:

1. I have reviewed this amendment to annual report on Form 10-K of Niagara Mohawk Power Corporation (the “Report”);

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

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

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

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

Date: July 3, 2003	/s/ John G. Cochrane
	John G. Cochrane
	Chief Financial Officer

NIAGARA MOHAWK POWER CORPORATION

EXHIBIT INDEX

99.1

Certification of CEO under Section 906 of the Sarbanes-Oxley Act of 2002

99.2

Certification of CFO under Section 906 of the Sarbanes-Oxley Act of 2002

NIAGARA MOHAWK POWER CORP /NY/ 10-K/A