Niagara Mohawk Power (NMKBP) 10-K/A 2004 FY Annual report (amended)

UNITED STATES
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, 2004

OR

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

For the transition period from ___________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 15, 2004
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 its Annual Report on Form 10-K for the fiscal year ended March 31, 2004 in order to provide the final version of its Consolidated Balance Sheets, as the registrant inadvertently filed an outdated draft version of its Consolidated Balance Sheets as part of its original submission.  This final version differs from the earlier outdated draft version in two respects:  (i) certain subtotals are corrected; and (ii) a reclassification is reflected as of March 31, 2003. There were no other changes to the Form 10-K as originally submitted.  The Item 8 included in the registrant's original submission should be disregarded as it is replaced in its entirety by the Item 8 in this amendment.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A. FINANCIAL STATEMENTS

• Reports of Independent Registered Public Accounting Firm

• Consolidated Statements of Operations, Consolidated Statements of Comprehensive Income (Loss), and Consolidated Statements of Retained Earnings for each of the two years in the period ended March 31, 2004, the sixty day period ended March 31, 2002, the thirty day period ended January 30, 2002, the three months ended March 31, 2001 (unaudited) and the year ended December 31, 2001

• Consolidated Balance Sheets at March 31, 2004 and 2003

• Consolidated Statements of Cash Flows for each of the two years in the period ended March 31, 2004, the sixty day period ended March 31, 2002, the thirty day period ended January 30, 2002, the three months ended March 31, 2001 (unaudited) and the year ended December 31, 2001

• Notes to Consolidated Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, of comprehensive income (loss), of retained earnings and of cash flows present fairly, in all material respects, the financial position of Niagara Mohawk Power Corporation and its subsidiaries at March 31, 2004 and 2003, and the results of their operations and their cash flows for each of the two years in the period ended March 31, 2004 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.






/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP




Boston, Massachusetts
May 6, 2004, except for Notes
D and E, as to which the dates
are May 10, 2004 and May 27, 2004,
respectively

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

In our opinion, the accompanying consolidated statements of operations, of comprehensive income (loss), of retained earnings 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 the year 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.






/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		For the	60 Day	30 Day	Three	For the
				year ended		year ended	period ended	period ended	months ended	year ended
				March 31,		March 31,	March 31,	January 30,	March 31,	December 31,
				2004		2003	2002	2002	2001	2001
				(Successor)		(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)
									(Unaudited)
Operating revenues:
	Electric			$ 3,284,017		$ 3,310,837	$ 539,758	$ 282,931	$ 823,566	$ 3,393,212
	Gas			779,600		708,613	149,947	79,691	356,140	721,501
			Total operating revenues	4,063,617		4,019,450	689,705	362,622	1,179,706	4,114,713
Operating expenses:
	Purchased electricity			1,591,652		1,594,221	231,721	111,444	291,053	1,304,242
	Purchased gas			478,647		393,796	83,477	46,651	249,760	419,324
	Fuel for electric generation			-		-	-	-	14,317	37,162
	Other operation and maintenance			791,110		840,367	158,367	116,485	248,196	952,853
	Disallowed nuclear investment costs			-		-	-	-	-	123,000
	Depreciation and amortization			200,650		198,253	32,877	16,671	77,768	292,224
	Amortization of stranded costs			194,114		149,415	23,533	40,911	91,073	393,136
	Other taxes			227,006		253,207	40,892	20,298	50,403	234,346
	Income taxes			138,843		93,277	26,362	4,036	24,368	9,582
			Total operating expenses	3,622,022		3,522,536	597,229	356,496	1,046,938	3,765,869
Operating income				441,595		496,914	92,476	6,126	132,768	348,844
	Other income (deductions)			(9,198)		(1,340)	777	2,349	6,631	72,896
Operating and other income				432,397		495,574	93,253	8,475	139,399	421,740
Interest:
	Interest on long-term debt			220,781		318,149	56,567	28,490	97,203	367,291
	Interest on debt to associated
	Companies			55,282		16,852	-	-	-	-
	Other interest			16,644		34,702	6,040	926	8,186	35,091
			Total interest expense	292,707		369,703	62,607	29,416	105,389	402,382
Net income (loss)				139,690		125,871	30,646	(20,941)	34,010	19,358
	Dividends on preferred stock			4,430		5,568	-	7,611	7,758	30,850
Income available to common shareholder(s)				$ 135,260		$ 120,303	$ 30,646	$ (28,552)	$ 26,252	$ (11,492)
Consolidated Statements of Comprehensive Income (Loss)
(In thousands of dollars)
					For the year ended March 31,	For the year ended March 31,	60 Day period ended March 31,	30 Day period ended January 30,	Three months ended March 31,		For the year ended December 31,
					2004	2003	2002	2002	2001		2001
					(Successor)	(Successor)	(Successor)	(Predecessor)	(Predecessor)		(Predecessor)
									(Unaudited)
Net income (loss)					$ 139,690	$ 125,871	$ 30,646	$ (20,941)	$ 34,010		$ 19,358
Other comprehensive income (loss):
	Unrealized gains (losses) on securities,
		net of tax			1,731	(710)	126	(81)	(671)		(857)
	Hedging activity, net of tax				2,425	600	2,674	1,084	3,621		(5,127)
	Additional minimum pension liability				(1,557)	-	-	(23,081)	267		(4,202)
			Total other comprehensive income (loss)		2,599	(110)	2,800	(22,078)	3,217		(10,186)
Comprehensive income (loss)					$ 142,289	$ 125,761	$ 33,446	$ (43,019)	$ 37,227		$ 9,172

Per share data is not relevant because the Company’s common stock is wholly-owned by Niagara Mohawk Holdings, Inc.

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

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Statements of Retained Earnings
(In thousands of dollars)
	For the year ended March 31,	For the year ended March 31,	60 Day period ended March 31,	30 Day period ended January 30,	Three months ended March 31,	For the year ended December 31,
	2004	2003	2002	2002	2001	2001
	(Successor)	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)
					(Unaudited)
Retained earnings at beginning of period	$ 85,706	$ 29,317	$ 138,492	$ 167,044	$ 215,696	$ 215,696
Net income (loss)	139,690	125,871	30,646	(20,941)	34,010	19,358
Purchase accounting adjustment	-	-	(138,492)	-	-	-
Call premium on preferred stock	-	-	(1,329)	-	-	-
Dividends on preferred stock	(4,430)	(5,568)	-	(7,611)	(7,758)	(30,850)
Dividend to Niagara Mohawk Holdings, Inc.	-	(63,914)	-	-	-	(37,160)
Retained earnings at end of period	$ 220,966	$ 85,706	$ 29,317	$ 138,492	$ 241,948	$ 167,044

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,
					2004	2003
					(Successor)	(Successor)
ASSETS
Utility plant, at original cost:
	Electric plant				$ 5,200,640	$ 5,091,435
	Gas plant				1,477,977	1,402,215
	Common Plant				333,789	351,987
	Construction work-in-progress				152,821	144,801
			Total utility plant		7,165,227	6,990,438
	Less: Accumulated depreciation and amortization				2,078,328	2,035,651
			Net utility plant		5,086,899	4,954,787
Goodwill					1,225,742	1,225,742
Pension intangible					10,990	12,150
Other property and investments					57,273	94,314
Current assets:
	Cash and cash equivalents				26,840	30,038
	Restricted cash (Note A)				12,163	25,350
	Accounts receivable (less reserves of $124,200 and
		$100,200, respectively, and includes receivables
		from associated companies of $516 and $227,
		respectively)			578,654	543,207
	Notes receivable				-	73
	Materials and supplies, at average cost:
		Gas storage			11,226	4,795
		Other			15,714	16,401
	Derivative instruments (Note A and L)				24,393	16,354
	Prepaid taxes				61,769	90,770
	Current deferred income taxes (Note G)				70,415	35,458
	Regulatory asset – swap contracts				182,000	192,000
	Other				13,389	10,483
			Total current assets		996,563	964,929
Regulatory and other non-current assets:
	Regulatory assets (Note B):
		Merger rate plan stranded costs			3,019,597	3,213,657
		Swap contracts regulatory asset			533,367	601,028
		Regulatory tax asset			151,080	143,765
		Deferred environmental restoration costs			309,000	301,000
		Pension and postretirement benefit plans			466,789	457,104
		Additional minimum pension liability			157,068	256,675
		Loss on reacquired debt			74,993	48,255
		Other			288,427	242,290
			Total regulatory assets		5,000,321	5,263,774
	Other non-current assets				38,151	35,169
			Total regulatory and other non-current assets		5,038,472	5,298,943
				Total assets	$ 12,415,939	$ 12,550,865

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,
					2004	2003
					(Successor)	(Successor)
CAPITALIZATION AND LIABILITIES
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			2,929,501	2,621,440
		Accumulated other comprehensive income			2,615	16
		Retained earnings			220,966	85,706
			Total common stockholder's equity		3,340,447	2,894,527
	Preferred equity (Note I):
		Cumulative preferred stock ($100 par value, optionally redeemable)			41,170	42,625
			Authorized - 3,400,000 shares
			Issued and outstanding - 411,715 and 426,248 shares, respectively
		Cumulative preferred stock ($25 par value, optionally redeemable)			25,155	55,655
			Authorized - 19,600,000 shares
			Issued and outstanding - 503,100 and 1,113,100 shares, respectively
	Long-term debt (Note E)				2,273,467	3,453,989
	Long-term debt to affiliates (Note E)				1,200,000	500,000
			Total capitalization		6,880,239	6,946,796
Current liabilities:
	Accounts payable (including payables to associated companies
		of $42,485 and $34,029, respectively)			285,965	375,767
	Customers' deposits				26,133	25,843
	Accrued interest				98,221	108,927
	Short-term debt to affiliates (Note F)				463,500	198,000
	Current portion of liability for swap contracts (Note A and L)				182,000	192,000
	Current portion of long-term debt (Note E)				532,620	611,652
	Other				125,461	111,904
		Total current liabilities			1,713,900	1,624,093
Non-current liabilities:
	Accumulated deferred income taxes (Note G)				1,348,503	1,157,796
	Liability for swap contracts (Note A and L)				533,367	601,028
	Employee pension and other benefits (Note H)				449,803	615,379
	Liability for environmental remediation costs				309,000	301,000
	Additional minimum pension liability				169,615	268,825
	Cost of removal regulatory liability (Note O)				313,545	307,106
	Other				697,967	728,842
		Total other non-current liabilities			3,821,800	3,979,976
Commitments and contingencies (Notes D):					-	-
				Total capitalization and liabilities	$ 12,415,939	$ 12,550,865

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

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flows
(In thousands of dollars)
				Year	Year	60 Day Period	30 Day Period	Three months	Year
				ended	ended	ended	ended	ended	ended
				March 31, 2004	March 31, 2003	March 31, 2002	January 30, 2002	March 31, 2001	December 31, 2001
				(Successor)	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)
								(Unaudited)
Operating activities:
	Net income (loss)			$ 139,690	$ 125,871	$ 30,646	$ (20,941)	$ 34,010	$ 19,358
	Adjustments to reconcile net income to net cash provided by
			(used in) operating activities:
		Depreciation and amortization		200,650	198,253	32,877	16,671	77,768	292,224
		Amortization of stranded costs		194,114	149,415	23,533	40,911	91,073	393,136
		Amortization of nuclear fuel		-	-	-	-	7,203	23,095
		Disallowed nuclear investment costs		-	-	-	-	-	123,000
		Provision for deferred income taxes		148,435	123,950	50,814	3,024	9,639	(8,774)
		Pension and other benefit plans expense		100,484	59,955	42,313	21,156	14,065	56,259
		Cash paid to pension and postretirement benefit
			plan trusts	(266,139)	(178,969)	(15,603)	(7,801)	(1,000)	(4,000)
		Reversal of deferred nuclear ITC’s		-	-	-	-	-	(79,711)
	Changes in operating assets and liabilities:
		Net accounts receivable (net of changes in accounts
			receivable sold)	(35,374)	(15,493)	(139,062)	(31,677)	(32,079)	1,153
		Materials and supplies		(5,744)	(377)	30,302	21,538	47,114	(8,571)
		Accounts payable and accrued expenses		(74,946)	143,015	(27,981)	34,261	(138,117)	(198,742)
		Accrued interest and taxes		(10,706)	(2,588)	28,979	264	19,599	(13,943)
		Other, net		(41,093)	9,281	(94,890)	19,786	(33,273)	(28,411)
			Net cash provided by (used in) operating activities	349,371	612,313	(38,072)	97,192	96,002	566,073
Investing activities:
	Construction additions			(317,302)	(244,814)	(24,959)	(13,323)	(51,737)	(247,134)
	Nuclear fuel			-	-	-	-	(2,304)	(3,822)
	Proceeds from the sale of generation assets			-	249,799	-	-	83,838	353,785
	Change in restricted cash			13,187	(17,268)	14,261	6,402	(205)	(17,798)
	Other investments			6,563	1,256	(3,176)	18,368	(16,261)	(33,793)
	Other, net			(17,294)	(17,678)	15,357	(22,839)	752	(14,368)
			Net cash provided by (used in) investing activities	(314,846)	(28,705)	1,483	(11,392)	14,083	36,870
Financing activities:
	Dividends paid on preferred stock			(4,430)	(5,568)	-	(7,611)	(7,758)	(30,850)
	Dividends paid on common stock to Holdings
		(including a return of capital of $86.1 million for fiscal year 2003)		-	(150,000)	-	-	-	(37,160)
	Reductions in long-term debt			(1,319,490)	(668,675)	(131,174)	(1,050)	(226,050)	(916,746)
	Proceeds from long-term debt			45,600	-	-	-	-	534,152
	Proceeds from long-term debt to affiliates			700,000	500,000	-	-	-	-
	Redemption of preferred stock			(33,903)	(2,131)	(390,289)	-	-	(3,050)
	Net change in short-term debt			265,500	(221,000)	419,000	-	115,000	(110,000)
	Equity contribution from parent			309,000	-	-	-	-	-
	Other, net			-	(16,078)	(2,391)	(23,048)	3,558	(8,179)
			Net cash used in financing activities	(37,723)	(563,452)	(104,854)	(31,709)	(115,250)	(571,833)
Net increase (decrease) in cash and cash equivalents				(3,198)	20,156	(141,443)	54,091	(5,165)	31,110
Cash and cash equivalents at beginning of period				30,038	9,882	151,325	97,234	66,123	66,124
Cash and cash equivalents at end of period				$ 26,840	$ 30,038	$ 9,882	$ 151,325	$ 60,958	$ 97,234
Supplemental disclosures of cash flow information:
Interest paid				$ 336,147	$ 336,102	$ 27,245	$ 23,647	$ 70,746	$ 373,100
Income taxes paid				$ 9,362	$ 34,799	$ -	$ -	$ 7	$ 51

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 in the United States of America (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 is a wholly-owned subsidiary of Niagara Mohawk Holdings, Inc. (Holdings), which in turn is wholly-owned by National Grid USA (National Grid).

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 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 2002 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 acquisition of Holdings by National Grid was completed for a consideration of approximately $3 billion in cash and American Depositary Shares.

The application of the purchase accounting method and implementation of the Merger Rate Plan resulted in substantial changes to the Company’s balance sheet, principally in the recording of goodwill, the write-down of regulatory assets, and the increase in the Company’s capital structure.

The closing of the merger with 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. For a further discussion of Company’s new rate agreement see Note B.

The purchase accounting method required the Company to revalue its assets and liabilities at their fair value. This revaluation resulted in an increase to Niagara Mohawk’s pension and postretirement benefit plan liabilities in the amount of approximately $440 million, with a corresponding offsetting increase to a regulatory asset account. See Note H.

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, was 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 and when events or circumstances indicate that the asset may be impaired. The Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the performance of the annual goodwill impairment test. The result of the annual analysis determined that no 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 AFUDC (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 (AFUDC): The Company capitalizes AFUDC as part of construction costs in amounts equivalent to the cost of funds devoted to plant under construction for its regulated business. AFUDC represents an allowance for the cost of funds used to finance construction. AFUDC is capitalized in "Utility plant" with offsetting non-cash credits to "Other interest" and “Other income (deductions)” on the Consolidated Statement of Operations. This method is in accordance with an established rate-making practice under which a utility is permitted a return on, and the recovery of, prudently incurred capital costs through their ultimate inclusion in rate base and in the provision for depreciation. AFUDC rates are determined in accordance with FERC and PSC regulations. The AFUDC rates in effect at March 31, 2004 and 2003 were 1.22 percent and 1.50 percent, respectively. AFUDC is segregated into its two components, borrowed funds and other funds, and is reflected in the “Other interest” and “Other income (deductions)” sections, respectively, in the Company’s Consolidated Statements of Operations. The amounts of AFUDC credits were recorded as follows:

	Year Ended March 31,	Year Ended March 31,	60 Day Period Ended March 31,	30 Day Period Ended January 30,	Three Months Ended March 31,	Year Ended December 31,
	2004	2003	2002	2002	2001	2001
($'s in 000's)	(Successor)	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)
					(Unaudited)
Other income (deductions)	$ (9)	$ 187	$ 167	$ 136	$ 798	$ 2,296
Other interest	565	384	180	173	906	2,728

Depreciation: For accounting and regulatory purposes, the Company’s depreciation is computed on the straight-line basis using the average service lives. 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:

	Year Ended March 31,	Year Ended March 31,	60 Day Period Ended March 31,	30 Day Period Ended January 30,	Three Months Ended March 31,	Year Ended December 31,
	2004	2003	2002	2002	2001	2001
	(Successor)	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)
Asset Category:					(Unaudited)
Electric	34	34	34	33	34	26
Gas	44	42	41	40	41	43
Common	17	17	16	16	16	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, 2004 and 2003 was approximately $132 million.

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, 2004 and 2003, approximately $9 million and $6 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.
In August 2001, the PSC approved certain rate plan changes. The changes allowed for certain commodity-related costs to be passed through to customers beginning September 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 (amended through the Company’s merger rate plan and ending December 2004) in July 2000 that includes a provision for the continuation of a full gas cost collection mechanism, effective August 2000. This gas cost collection mechanism was originally reinstated in an interim agreement that became effective November 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: Regulated federal and state income taxes are recorded under the provisions of Financial Accounting Standards Board (FASB) SFAS No. 109 “Accounting for Income Taxes”. 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 a 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. 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.

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 approximated $113 million, $62 million and $6 million for the years ended March 31, 2004 and 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 and cash equivalents.

Restricted Cash: Restricted cash consists of margin accounts for hedging activity, health care claims deposits, New York State Department of Conservation securitization for certain site cleanup, and worker’s compensation premium deposit.

Derivatives: The Company accounts for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (FAS 133), and SFAS No. 149,
“Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” as amended. Under the provisions of FAS 133, all derivatives except those qualifying for the normal purchase normal sale exception are recognized on the balance sheet at their fair value. Fair value is determined using current quoted market prices. If a contract is designated as a cash flow hedge, the change in its market value is generally deferred as a component of other comprehensive income until the transaction it is hedging is completed. Conversely, the change in the market value of a derivative not designated as a cash flow hedge is deferred as a regulatory asset or liability. A cash flow hedge is a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. To qualify as a cash flow hedge, the fair value changes in the derivative must be expected to offset 80% to 120% of the changes in fair value or cash flows of the hedged item.

The Company has received approval from the PSC to establish a regulatory asset or liability derivative instruments that did not qualify for hedge accounting and were the result of regulatory rulings.

Sale of Customer Receivables: The Company had established a single-purpose financing subsidiary, NM Receivables LLC (NMR), to purchase and resell a financial interest in a pool of the Company’s customer receivables. NMR was dissolved during fiscal 2004. See Note D. Commitments and Contingencies for a complete description of the operations of NMR and its dissolution during the current fiscal year. The Company adopted SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities - a replacement of SFAS No. 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.

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. See Note C. Accumulated Other Comprehensive Income (Loss).

Additional minimum pension liability: Under current rate agreements with the PSC, the Company does not recognize its additional minimum pension liability (AML) for its qualified plan as a component of accumulated other comprehensive income but as a regulatory asset. The additional minimum pension liability for its non-qualified plan is recognized in accumulated other comprehensive income.

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.

Power Purchase Agreements: The Company accounts for its power purchase agreements as executory contracts. The Company assesses several factors in determining how to account for its power purchase contracts. These factors include:

• the term of the contract compared to the economic useful life of the facility generating the electricity;

• the involvement, if any, that the Company has in operating the facility;

• the amount of any fixed payments the Company must make, even if the facility does not generate electricity; and

• the level of control the Company has over the amount of electricity generated by the facility, and who bears the risk in the event the facility is unable to generate.

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 adopted FAS 143 during the fiscal year ended March 31, 2004 (see Note O. Cost of Removal). The adoption of this statement did not have a material impact on the Company’s financial position, results of operations, or cash flows.

In December 2003 the FASB revised SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (FAS 132-R). FAS 132-R retains the disclosure requirements contained in the original statement and requires new disclosures about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension and other defined benefit postretirement plans. FAS 132-R is effective for fiscal years ending after December 15, 2003 and for interim periods beginning thereafter. The Company has adopted FAS 132-R during the current fiscal year. This standard does not change the measurement or recognition of the aforementioned plans and, as such, the adoption of this statement has not had any effect on the Company’s financial position, results of operations, or cash flows.

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of ARB 51” (FIN 46). FIN 46 requires the consolidation of entities in which an enterprise absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interest in the entity. Historically, entities have generally been consolidated by an enterprise when it has a controlling financial interest through ownership of a majority voting interest in the entity. The objectives of FIN 46 are to provide guidance on the identification of Variable Interest Entities (VIEs) for which control is achieved through means other than a controlling financial interest, and how to determine which business enterprise, as the primary beneficiary, should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the entity lacks sufficient equity to absorb expected losses without additional subordinated financial support or (2) its at-risk equity holders as a group are not able to make decisions that have a significant impact on the success or failure of the entity’s ongoing activities.

In December 2003, the FASB modified FIN 46 with FIN 46-R to make certain technical corrections to the standard and to address certain implementation issues. FIN 46, as originally issued, was effective immediately for VIEs created or acquired after January 31, 2003. FIN 46-R delayed the effective date of the interpretation to no later than March 31, 2004, (for calendar-year enterprises), except for Special Purpose Entities for which the effective date was December 31, 2003. The adoption of FIN 46-R has not had a material impact on the Company's financial position, results of operations, or cash flows.

In January 2004, the FASB issued FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act)” (FSP 106-1). FSP 106-1 is effective for annual fiscal periods ending after December 7, 2003. FSP 106-1 permits employers that sponsor postretirement benefit plans (plan sponsors) that provide prescription drug benefits to retirees to make a one-time election to defer accounting for any effects of the Act. FSP 106-1 requires all plan sponsors to provide certain disclosures, regardless of whether they choose to account or defer accounting. If deferral is elected, the deferral must remain in effect until the earlier of (1) the issuance of guidance by the FASB on how to account for the federal subsidy to be provided to plan sponsors under the Act or (2) the remeasurement of plan assets and obligations subsequent to January 31, 2004. The Company has decided not to make an election until further accounting guidance is issued by the FASB. The measurement of the accumulated postretirement benefit obligation and net postretirement benefit cost in the financial statements and accompanying notes do not reflect the effect of the Act on the Company's postretirement benefit plans.

Reclassifications: Certain amounts from prior years have been reclassified on the accompanying consolidated financial statements to conform to the fiscal 2004 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” (FAS 71) 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 $5.2 billion and $5.5 billion at March 31, 2004 and 2003, respectively. 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 (electricity transmission and distribution business) continues to be rate-regulated on a cost-of-service basis and, accordingly, the Company continues to apply FAS 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 FAS 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 FAS 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 most of its regulatory assets.

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 timing differences related to depreciation. These amounts are recovered and amortized as the related temporary differences reverse.

Deferred environmental restoration costs: This regulatory asset represents deferred costs associated with the Company’s share of the estimated costs to investigate and perform certain remediation activities at sites which it may be associated. The Company’s rate plans provided for specific rate allowances for these costs, with variances deferred for future recovery or pass-back to customers. The Company believes future costs, beyond the expiration of current rate plans, will continue to be recovered through rates.

Pension and post-retirement benefit plans: Excess costs of the Company’s pension and post-retirement benefits plans over amounts received in rates are deferred to a regulatory asset to be recovered in a future period.

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

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 New York Independent System Operator (NYISO) costs that were deferred for future recovery.

See Notes H, D, and L 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 Securities	Adjustment	Hedges	Income (Loss)
March 31, 2002				$ 126	$ -	$ -	$ 126
	Unrealized gains (losses) on securities,
		net of taxes		(710)			(710)
	Hedging activity, net of taxes					600	600
March 31, 2003				$ (584)	$ -	$ 600	$ 16
	Unrealized gains (losses) on securities,
		net of taxes		1,731			1,731
	Hedging activity, net of taxes					2,425	2,425
	Change in additional minimum
		pension liability			(1,557)		(1,557)
March 31, 2004				$ 1,147	$ (1,557)	$ 3,025	$ 2,615

Taxes on other comprehensive income for the following periods were (in thousands of $’s):

	For the year ended March 31,	For the year ended March 31,	60 Day period ended March 31,	30 Day period ended January 30,	Three months ended March 31,	For the year ended December 31,
	2004	2003	2002	2002	2001	2001
	(Successor)	(Successor)	(Successor)	(Predecessor)	(Predecessor) (Unaudited)	(Predecessor)
Unrealized gain/(losses) on securities	$ 1,154	$ 758	$ (92)	$ 59	$ 361	$ 612
Hedging activities	1,617	(452)	(1,976)	(800)	(1,950)	3,790

NOTE D – 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. This filing is pending before the PSC, and the Company cannot predict the outcome of this filing.

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, 2004 are summarized in the table below. The Company did not enter into any new agreements in fiscal 2004 or 2003. For a detailed discussion of the financial swap agreements that the Company has entered into to hedge the costs of purchased electricity (which are not included in the table below), see Note L. Derivatives and Hedging Activities.

(In thousands of dollars)
Fiscal Year
Ended	Estimated
March 31,	Payments
2005	$ 498,366
2006	410,613
2007	408,266
2008	381,254
2009	385,523
Thereafter	2,666,623

In addition to the contractual commitments described above, the Company entered into a four-year contract, which expired in June 2003, that gave it the option to buy additional power at market prices from the Huntley coal-fired generation plant. 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, 2004, for the next five years, and thereafter.

	(In thousands of dollars)
Fiscal Year
Ended		Gas Storage/
March 31,	Gas Supply	Pipeline
2005	$ 145,288	$ 61,454
2006	76,999	55,689
2007	42,249	52,300
2008	-	52,215
2009	-	5,310
Thereafter	-	14,943

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, 2004, the Company’s firm gas supply commitments have varying expiration dates, the latest of which is October 2006. The gas storage and transportation commitments have varying expiration dates with the latest being October 2012.

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.

The Company is currently aware of 103 sites with which it may be associated, including 56 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 (PRP). 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.

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. 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. It is more difficult to estimate the costs to remediate certain non-owned sites, because they have not undergone site investigations.

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 amounts of $309 million and $301 million which is reflected in the Company’s Consolidated Balance Sheets at March 31, 2004 and 2003, respectively. The potential high end of the range is presently estimated at approximately $532 million. The reserve has been increased by $8 million since March 31, 2003 primarily due to the accrual of an additional $26 million associated with its Harbor Point site and other accruals, offset by anticipated site related expenditures. The Company had previously filed an Article 78 petition to contest the New York Department of Environmental Conservation’s more costly remediation plan of the site. During fiscal 2004, the petition was denied by the court and the additional estimated costs to remediate Harbor Point were accrued. This additional accrual has been offset by reductions in expected values on sites resulting from regular spending as well as a decrease of $13 million as the expected value on the Company’s Hudson (Water Street) site was adjusted to reflect costs as based on an actual bid, including long-term monitoring.

The Merger Rate Plan provides for the continued application of deferral accounting for variations in spending from amounts provided in rates. The Company has recorded a regulatory asset representing the investigation, remediation, and monitoring obligations to be recovered from ratepayers. 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, financial condition or cash flows.

Nuclear Contingencies: As of March 31, 2004 and 2003, the Company has a liability of $143 million and $142 million, respectively, in other non-current 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, who 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.

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 Supreme Court (Albany County) a petition for review of decisions by 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 company’s 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 the Company’s financial position or results of operations. However, AMP’s petition for review also challenges the lawfulness of the Company’s collection of exit fees from departing municipalities, regardless of the methodology used to calculate those fees. On October 27, 2003, the court dismissed AMP’s petition. AMP made a timely filing to appeal the court’s decision but has not perfected its appeal.

Niagara Mohawk Power Corp. v. Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C. The Company previously owned three power plants (the Plants), which it sold to three affiliates of NRG Energy, Inc. in 1999: Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C. (collectively, the NRG Affiliates). The Company is in involved in three proceedings with the NRG affiliates to recover bills for station service rendered to the Plants; a collections action filed by the Company against the NRG affiliates in New York State Supreme Court in October 2000; a petition filed by the Company at the FERC in November 2002, and an Article 78 Petition filed by the NRG Affiliates in New York Supreme Court in March 2004, challenging the state retail standby distribution tariff. The main issue in all three proceedings is whether the NRG Affiliates will be permitted to bypass the Company’s state-jurisdictional retail charges for station service. The State Supreme Court lawsuit filed by the Company has been stayed by agreement, the parties are awaiting a decision from FERC on the Company’s petition, and the parties have agreed to stay the NRG Affiliates’ Article 78 petition pending appeal of a FERC decision on May 10, 2004 in another proceeding. The May 10, 2004 Order denied rehearing of objections to FERC’s approval of the NYISO wholesale station service tariff, on which the NRG Affiliates are relying in part to avoid payment of the state retail distribution tariff for station service. FERC’s May 10, 2004 Order is discussed below under Retail Bypass. As of March 31, 2004, the NRG Affiliates owed the Company approximately $39 million for station service. In the event it is determined that the Company may not bill the NRG Affiliates for station service under its state tariff, the Company would seek recovery under its rate plans.

New York State v. Niagara Mohawk Power Corp. et al.: On January 10, 2002, the New York State Attorney General filed a civil action against the Company, NRG Energy, Inc. and certain of its affiliates in U.S. District Court for the Western District of New York for alleged violations of the federal Clean Air Act, related state environmental statutes, and the common law, at the Huntley and Dunkirk power plants. The State alleged that between 1982 and 1999, the Company modified the two plants 55 times without obtaining proper preconstruction permits and implementing proper pollution equipment controls.

On March 27, 2003, the court issued an order granting in part the Company’s motion to dismiss, which had been filed in 2002. Based on applicable statutes of limitations, the court reduced the number of projects allegedly requiring preconstruction permits under the Clean Air Act from 55 to nine.

On December 31, 2003, the court granted the State’s motion to amend the complaint, allowing it to assert operating permit violations against the Company and NRG. In so ruling, the court stated that monetary penalties for actions outside the statute of limitations period would still be barred. the Company answered the amended complaint on March 2, 2004, and filed a counterclaim against the State of New York in response to its common law public nuisance claim, seeking contribution for the Company’s portion of any alleged harm caused by emissions from facilities that the State owns or to which it has given permits. The State has moved to dismiss the counterclaim. Trial is scheduled for March 2006.

Niagara Mohawk Power Corporation v. NRG Energy, Inc., Huntley Power L.L.C. and Dunkirk Power L.L.C. With respect to the claims asserted in the Clean Air Act lawsuit discussed above, NRG and its Affiliates have taken the position that the Company is responsible at least in part for the costs of pollution control equipment and related fines and penalties, notwithstanding contrary language in the agreement governing the sale of the Plants to the NRG Affiliates. As a result, on July 13, 2001, the Company sued NRG and the NRG Affiliates in New York State Supreme Court (Onondaga County), seeking a declaratory ruling that under the agreement, NRG is responsible for the costs of any pollution control upgrades and mitigation, as well as post-sale fines and penalties, that may result from the Clean Air Act suit. In response, NRG filed a counterclaim and filed a motion for partial summary on its counterclaim. Hearing on NRG’s motion is scheduled for July 28, 2004.

Retail Bypass: In approving Power Choice, the rate plan in effect prior to the Merger Rate Plan, the PSC authorized changes to the Company’s retail tariff providing for the recovery of an exit fee for customers that leave the Company’s system. The retail tariff governs the application and calculation of the exit fee. The exit fee also applies to municipalities seeking to serve customers in the Company’s service area.

On September 22, 2002, a different type of retail bypass issue was presented in a filing with FERC by the NYISO seeking to implement a new station service rate which also provided that generators could net their station service electricity over a 30-day period. On November 22, 2002, FERC issued an order accepting the NYISO’s new rate, over the Company’s protest (the FERC NYISO Order). The FERC NYISO Order has allowed generators to argue that they should be able to avoid paying state-approved charges for retail deliveries when they take service under the NYISO tariff. On July 10, 2003, the Company filed modifications to its standby service rates with the PSC, which the PSC approved on November 25, 2003. The tariff modifications unbundle the transmission service component provided under the NYISO’s new rate but continue the Company’s own retail distribution charges to these customers.

A number of generators have complained or withheld payments associated with the Company’s delivery of station service to their generation facilities, including NRG Energy, Inc. On December 23, 2003, FERC issued two orders on complaints filed by AES Somerset, L.L.C. (AES) and Nine Mile Point Nuclear Station, L.L.C. (Nine Mile) (together, the AES and Nine Mile FERC Orders), both of which are station service customers of the Company. The two orders allow these generators to net their station service electricity over a 30-day period and to avoid state-authorized charges for deliveries made over distribution facilities. While it is not entirely clear from reading the AES and Nine Mile FERC Orders, it is possible to construe them to have retroactive effect back to the date the plant was sold to AES by a third party. The net effect of these FERC decisions is that the two generators will no longer have to pay the Company for station service charges for electricity. The AES and Nine Mile FERC Orders are in direct conflict with the state-approved tariffs and the orders of the PSC on station service rates. The FERC orders, if upheld, will permit these generators to completely bypass the Company’s state-jurisdictional retail charges, including those set forth in the filing that was approved by the PSC on November 25, 2003. On February 23, 2004, the Company received orders granting rehearing for further consideration from the FERC in both the AES and Nine Mile Point proceedings. No further action on the rehearing requests has occurred to date.

On May 10, 2004, FERC issued an order denying motions for clarification filed by the Company and other parties with respect to the FERC NYISO Order, and reaffirmed its reasoning of the AES and Nine Mile FERC Orders. In so ruling, FERC indicated that the NYISO station service would be limited to merchant generators self-supplying their own power, and should not be interpreted to apply to self-supplying retail industrial and commercial customers. The Company intends to appeal.

The AES and Nine Mile FERC Orders and FERC NYISO Orders have increased the risk that generators will be able to bypass local distribution company charges (including stranded cost recovery charges) when receiving service through the NYISO. To the extent that the Company experiences any lost revenue attributable to retail bypass, it is permitted to recover these lost revenues under its rate plans.

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	2004	2003	Series	2004	2003
First Mortgage Bonds:				*Promissory Notes(3):
6 7/8%	2003	$ -	$ 85,000	2015	$ 100,000	$ 100,000
7 3/8%	2003	-	220,000	2023	69,800	69,800
8%	2004	232,425	232,425	2025	75,000	75,000
6 5/8%	2005	110,000	110,000	2026	50,000	50,000
9 3/4%	2005	137,981	137,981	2027	25,760	25,760
7 3/4%	2006	275,000	275,000	2027	93,200	93,200
*6 5/8%(1)	2013	45,600	45,600	Note Payable to
7 7/8%	2024	-	170,257	National Grid USA	-	500,000
*5.15%	2025	75,000	75,000	Notes Payable to Holdings
*7.2%(2)	2029	115,705	115,705	5.80% Due 2012	500,000	-
Total First Mortgage				3.83% Due 2010	350,000	-
Bonds		991,711	1,466,968	3.72% Due 2009	350,000	-
				Other	195	8,517
Senior Notes:				Unamortized discount	(2,018)	(6,020)
7 3/8%	2003	-	302,439	Total Long-Term Debt	4,006,087	4,565,641
5 3/8%	2004	300,000	300,000	Less long-term debt due
7 5/8%	2005	302,439	302,439	within one year	532,620	611,652
8 7/8%	2007	200,000	200,000	Long-Term Debt due after	$ 3,473,467	$ 3,953,989
7 3/4%	2008	600,000	600,000	one year
8 1/2%	2010	-	487,475
Unamortized discount
on 8 1/2% Senior Note		-	(9,937)
Total Senior Notes		$ 1,402,439	$ 2,182,416

⁽¹⁾ Refinanced to auction rate mode on December 11, 2003. Effective interest rate at March 31, 2004 was 1.18 percent.
⁽²⁾ Refinanced to auction rate mode on May 27, 2004.

⁽³⁾ Refinanced to auction rate mode on May 1, 2003. Effective interest rate at March 31, 2004 was 1.19 percent
*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 short-term adjustable interest rates (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 1.24 percent for the year ended March 31, 2004, 1.36 percent for the year ended March 31, 2003, 1.12 percent for the three months ended March 31, 2002, and 2.50 percent for 2001 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 (which the company subsequently sold) 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 $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 restructuring of the $414 million of tax exempt bonds and the exchange of the $500 million note payable to National Grid USA for a $500 million note payable to Holdings were accomplished through noncash transactions.

The aggregate maturities of long-term debt for the five years subsequent to March 31, 2004, excluding capital leases are approximately:

($'s in millions)
Fiscal Year	Amount
2005	$ 533
2006	550
2007	275
2008	200
2009	600
Thereafter	1,850
Total	$ 4,008

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 at March 31, 2004 and 2003. The non-current portion of capital lease obligations is reflected in the “Other” line item on the Consolidated Balance Sheet and was approximately $5 million and $6 million at March 31, 2004 and 2003, respectively.

At March 31, 2004, the Company's long-term debt had a fair value of approximately $3.1 billion. The fair market value of the Company’s long-term debt was estimated based on the debts’ coupons and remaining lives along with the current interest rate conditions.

Early Extinguishment of Debt

During the years ended March 31, 2004 and 2003 and the three months ended March 31, 2002, the Company defeased or redeemed approximately $658 million, $122 million, and $119 million, respectively, in long-term debt prior to its scheduled maturity.

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 – SHORT-TERM DEBT

The Company had short-term debt outstanding of $464 million and $198 million at March 31, 2004 and 2003, respectively, from the inter-company money pool. The Company has regulatory approval from the Securities and Exchange Commission (SEC), under the Public Utility Holding Company Act of 1935, to issue up to $1 billion of short-term debt. National Grid 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 average interest rate for the money pool was 1.11% and 1.62% for fiscal 2004 and 2003, respectively.

The Company had no short-term debt outstanding to third-parties at March 31, 2004 or 2003.

NOTE G – FEDERAL AND STATE 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 Operations and the computed amount at the statutory tax rate:

			60 Day Period	30 Day Period	Three Months
	Year Ended	Year Ended	Ended	Ended	Ended	Year Ended
	March 31,	March 31,	March 31,	January 30,	March 31,	December 31,
In thousands of dollars	2004	2003	2002	2002	2001	2001
					(Unaudited)
	(Successor)	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)
Components of federal and state income taxes:
Current tax expense (benefit):
Federal	$ (12,003)	$ (34,908)	$ (1,672)	$ 10,395	$ 6,519	$ 3,637
State	(474)	14,320	(6,698)	357	430	386
	(12,477)	(20,588)	(8,370)	10,752	6,949	4,023
Deferred tax expense (benefit):
Federal	128,426	111,157	24,106	(6,194)	11,108	(84,073)
State	20,022	(344)	10,098	(780)	(1,109)	1,178
	148,448	110,813	34,204	(6,974)	9,999	(82,895)
Total	$ 135,971	$ 90,225	$ 25,834	$ 3,778	$ 16,948	$ (78,872)
Total income taxes in the consolidated statements of operations:
Income taxes charged/
(credited) to operations	$ 138,843	$ 93,277	$ 26,362	$ 4,036	$ 24,368	$ 9,582
Income taxes credited to
"Other income (deductions)"	(2,872)	(3,052)	(528)	(258)	(7,420)	(88,454)
Total	$ 135,971	$ 90,225	$ 25,834	$ 3,778	$ 16,948	$ (78,872)

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

	Year Ended March 31,	Year Ended March 31,	60 Day Period Ended March 31,	30 Day Period Ended January 30,	Three Months Ended March 31,	Year Ended December 31,
	2004	2003	2002	2002	2001	2001
					(Unaudited)
	(Successor)	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)
Computed tax	$ 96,481	$ 75,641	$ 19,768	$ (5,883)	$ 17,835	$ (20,830)
Increase (reduction) including those attributable to
Flow-through of certain tax adjustments:
Depreciation	21,397	12,183	3,202	1,493	17,112	18,620
Cost of removal	(6,857)	(6,730)	(1,139)	(583)	(7,682)	(6,441)
Allowance for funds used
during construction - (a)	3	642	133	47	(1,527)	(806)
State income taxes	12,736	20,174	2,541	1,839	(765)	1,564
Non-deductible executive
compensation	-	(9,878)	-	9,878	-	-
Accrual to return adjustment	19,842	6,934	-	-	-	-
Goodwill adjustments	-	-	-	(1,953)	-	-
Debt premium & mortgage
recording tax	(1,556)	3,196	275	51	661	664
Real estate taxes	-	(9,300)	-	-	-	(414)
Amortization of capital stock	-	-	-	40	661	548
Dividends exclusion – federal
income tax returns	(149)	-	(67)	(34)	(486)	(468)
Provided at other than statutory
Rate	(2)	(2)	4	(2)	-	(4)
Voluntary Early Retirement
Plan	-	(251)	-	-	-	11,272
Allocation percentage/annualization	-	-	-	-	(3,002)	-
Subsidiaries	250	-	(173)	(96)	(313)	(1,115)
Deferred investment tax credit
reversal (b)	(2,872)	(3,029)	(528)	(258)	(7,420)	(86,034)
Other	(3,302)	645	1,818	(761)	1,874	4,572
Total	39,490	14,584	6,066	9,661	(887)	(58,042)
Federal income taxes	$ 135,971	$ 90,225	$ 25,834	$ 3,778	$ 16,948	$ (78,872)

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

(b) Deferred investment tax credits of $79.7 million related to the generation assets that have been sold have been taken into income in 2001 in accordance with IRS rules.

The deferred tax liabilities (assets) were comprised of the following:

	March 31,	March 31,
In thousands of dollars	2004	2003
	(Successor)	(Successor)
Alternative minimum tax	$ 81,639	$ 81,639
Unbilled revenues	22,611	16,890
Non-utilized NOL carryforward	318,216	554,821
Liability for environmental costs	148,325	131,750
Voluntary early retirement program	219,237	199,980
Bad debts	29,474	12,516
Pension and other post-retirement benefits	40,830	49,472
Other	265,082	279,862
Total deferred tax assets	1,125,414	1,326,930
Depreciation related	(921,798)	(857,711)
Investment tax credit related	(43,203)	(46,075)
Deferred environmental restoration costs	(148,325)	(131,750)
Merger rate plan stranded costs	(896,816)	(1,158,204)
Merger fair value pension and OPEB adjustment	(146,898)	(163,890)
Bond redemption and debt discount	(30,772)	(22,597)
Pension and other post-retirement benefits	(110,163)	(26,691)
Other	(105,527)	(42,350)
Total deferred tax liabilities	(2,403,502)	(2,449,268)
Net accumulated deferred income tax liability	$(1,278,088)	$(1,122,338)
Current portion (net deferred tax asset)	70,415	35,458
Net accumulated deferred income tax liability (non-current)	$(1,348,503)	$(1,157,796)

The Company has been audited and reported on by the Internal Revenue Service (IRS) through December 31, 1998.

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 net operating loss (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, 2004 and 2003 was $909 million and $1.6 billion, respectively. 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.

There were no valuation allowances for deferred tax assets at March 31, 2004 or 2003.


NOTE H - EMPLOYEE BENEFITS

Summary
The Company has a non-contributory defined benefit pension plan covering substantially all employees. The pension plan is a cash balance pension plan design and under that design, pay-based credits are applied based on service time, and interest credits are applied based on an average annual 30-year Treasury bond yield. In addition, a large number of employees hired by the Company prior to July 1998 are cash balance design participants who receive a larger benefit if so yielded under pre-cash balance conversion final average pay formula provisions. Employees hired by the Company following the August 1998 cash balance design conversion participate under cash balance design provisions only.

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

The Company provides health care and life insurance coverage to eligible retired employees. Eligibility is based on certain age and length of service requirements and in some cases retirees must contribute to the cost of their coverage.

Funding Policy
Funding policy is determined largely by the Company’s settlement agreements with the PSC and what is recovered in rates. However, the contribution for any year will not be less than the minimum contribution required by federal law or greater than the maximum tax-deductible amount.

Investment Strategy
The Company manages its pension plans investments to minimize the long-term cost of operating the plans, with a reasonable level of risk. Risk tolerance is determined as a result of a periodic asset/liability study which analyzes plan liabilities and plan funded status and results in the determination of the allocation of assets across equity and fixed income. Equity investments are broadly diversified across U.S. and non-U.S. stocks, as well as across growth, value, and small and large capitalization stocks. Likewise, the fixed income portfolio is broadly diversified across the various fixed income market segments. Investment risk and return is reviewed by the investment committee on a quarterly basis.

The target asset allocation for the benefit plans is:

	2004	2003
U.S. Equities	42%	50%
Global Equities (including U.S.)	7%	-
Non-U.S. Equities	11%	15%
Fixed Income	35%	35%
Private Equity and Property	5%	-
	100%	100%

The target asset allocation for the other post-retirement benefits plan is:

	2004	2003
U.S. Equities	50%	50%
Non U.S. Equities	15%	15%
Fixed Income	35%	35%
	100%	100%

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

The benefit plans’ costs used the following assumptions:

Pension Benefits
			Year Ended	Year Ended	Year Ended	Year Ended
			March 31,	March 31,	March 31,	December 31,
			2004	2003	2002	2001
			(Successor)	(Successor)	(Successor)	(Predecessor)
Weighted average assumptions used to determine net periodic cost:
	Discount rate		6.25%	6.25%	7.50%	7.25%
	Rate of compensation increase		3.25%	3.25%	3.25%	2.50%
	Expected return on plan assets		8.50%	8.50%	8.75%	9.50%
Other Post-retirement benefits
			Year Ended	Year Ended	Year Ended	Year Ended
			March 31,	March 31,	March 31,	December 31,
			2004	2003	2002	2001
			(Successor)	(Successor)	(Successor)	(Predecessor)
Weighted average assumptions used to determine net periodic cost:
	Discount rate		6.25%	6.25%	7.50%	7.25%
	Rate of compensation increase		3.25%	3.25%	3.25%	2.50%
	Expected return on plan assets		8.00%	8.50%	8.75%	9.50%
	Medical trend
		Initial	10.00%	10.00%	10.00%	9.00%
		Ultimate	5.00%	5.00%	5.00%	5.00%
		Year ultimate rate reached	2009	2008	2007	2006

The benefit plans’ included the following components of expense:

			Pension Benefits
					60 Day Period	30 Day Period
			Year Ended	Year Ended	Ended	Ended	Year Ended
			March 31,	March 31,	March 31,	January 30,	December 31,
			2004	2003	2002	2002	2001
			(Successor)	(Successor)	(Successor)	(Predecessor)	(Predecessor)
Net periodic benefit cost, for the year ended March 31
	Service cost		$ 28,093	$ 24,970	$ 4,886	$ 2,866	$ 32,046
	Interest cost		74,863	83,493	14,637	7,816	88,315
	Expected return on plan assets		(71,391)	(75,613)	(14,751)	(7,567)	(94,247)
	Amortization of initial obligation		-	-	-	191	2,240
	Amortization of unrecognized prior service cost		1,160	-	-	801	8,464
	Amortization of unrecognized (gain)/loss		18,026	5,559	-	(174)	(1,122)
	Net periodic benefit costs before settlements
		and curtailments	50,751	38,409	4,772	3,933	35,696
	Settlement & curtailment (gain)/loss		21,798	29,548	(16,726)	-	28,752
	Special termination benefits		14,300	-	44,000	25,674	-
	Net periodic benefit costs		$ 86,849	$ 67,957	$ 32,046	$ 29,607	$ 64,448
			Other Post-retirement Benefits
					60 Day Period	30 Day Period
			Year Ended	Year Ended	Ended	Ended	Year Ended
			March 31,	March 31,	March 31,	January 30,	December 31,
			2004	2003	2002	2002	2001
			(Successor)	(Successor)	(Successor)	(Predecessor)	(Predecessor)
Net periodic benefit cost, for the year ended March 31
	Service cost		$ 8,629	$ 6,745	$ 1,348	$ 1,064	$ 11,265
	Interest cost		57,952	55,551	8,806	3,792	41,664
	Expected return on plan assets		(34,578)	(23,642)	(3,458)	(2,071)	(24,436)
	Amortization of initial obligation		-	-	-	908	10,890
	Amortization of unrecognized prior service cost		-	-	-	302	(7,207)
	Amortization of unrecognized (gain)/loss		22,996	(498)	-	1,332	7,101
	Net periodic benefit costs before settlements
		and curtailments	54,999	38,156	6,696	5,327	39,277
	Settlement and curtailment (gain)/loss		-	-	-	-	3,179
	Special termination benefits		641	-	8,571	-	-
	Net periodic benefit costs		$55,640	$ 38,156	$ 15,267	$ 5,327	$ 42,456

The following table provides a reconciliation of the changes in the plans’ fair value of assets for the fiscal years 2004 and 2003, the expected contributions to the trust in the 2005 fiscal year, and the % distribution of the fair market value of the types of assets held in the benefit plans’ trusts.

			Pension Benefits		Other Post-retirement Benefits
			Year Ended	Year Ended	Year Ended	Year Ended
			March 31,	March 31,	March 31,	March 31,
			2004	2003	2004	2003
			(Successor)	(Successor)	(Successor)	(Successor)
Change in plan assets:
	Beginning balance		$ 737,593	$ 988,535	$ 330,749	$ 276,870
		Actual return on plan assets	207,264	(120,801)	92,305	(27,296)
		Employer contributions	90,194	97,794	175,945	81,175
		Benefit payments	(54,689)	(53,049)	(9,521)	-
		Settlements	(134,462)	(172,427)	-	-
		Dispositions	-	(2,459)	-	-
	Ending Balance		$ 845,900	$ 737,593	$ 589,478	$ 330,749
Distribution of plan assets
	Debt securities		33%	39%	35%	35%
	Equity securities		67%	57%	63%	35%
	Other		-	4%	2%	30%
	Total market value of assets		100%	100%	100%	100%
Estimated contributions in following year			$ 85,000	N/A*	$ 55,000	N/A*

* Not required for disclosure for the year ended March 31, 2003.
The following table provides a reconciliation of the changes in the plans’ fair value benefit obligation for the fiscal years 2004 and 2003, accumulated benefit obligation for the pension plans at March 31, and the assumption used in developing that obligation.

			Pension Benefits		Other Post-retirement Benefits
			Year ended	Year ended	Year ended	Year ended
			March 31,	March 31,	March 31,	March 31,
			2004	2003	2004	2003
			(Successor)	(Successor)	(Successor)	(Successor)
Accumulated benefit obligation			$ 1,234,898	$ 1,219,914	N/A*	N/A*
Change in benefit obligation:
	Beginning balance		$ 1,296,660	$ 1,231,149	$ 932,596	$ 743,289
		Service cost	28,093	24,970	8,629	6,745
		Interest cost	74,863	83,493	57,952	55,551
		Actuarial losses	73,783	173,522	111,361	183,764
		Plan amendments	-	12,150	-	-
		Benefit payments	(54,689)	(53,049)	(52,176)	(56,753)
		Settlements	(134,462)	(172,427)	-	-
		Special termination benefits	14,300	-	641	-
		Dispositions**	-	(3,148)	-	-
	Ending Balance		$ 1,298,548	$ 1,296,660	$ 1,059,003	$ 932,596
Reconciliation of accrued cost, end of period
	Fair value of plan assets at end of period		$ 845,900	$ 737,593	$ 589,478	$ 330,749
	Funded status		$ (452,648)	$ (559,067)	$ (469,525)	$ (601,847)
	Unrecognized prior service cost		10,990	12,150	-	-
	Unrecognized net loss		222,270	324,931	239,110	208,454
	Net amount recognized at March 31,		$ (219,388)	$ (221,986)	$ (230,415)	$ (393,393)
Amounts recognized in the Consolidated Balance Sheets consists of:
	Employee pension and other benefits liability		$ (388,998)	$ (490,811)	$ (230,415)	$ (393,393)
	Intangible asset		10,990	12,150	-	-
	Regulatory asset		157,068	256,675	-	-
	Accumulated other comprehensive income		1,552	-	-	-
	Net amount recognized at March 31,		$ (219,388)	$ (221,986)	$ (230,415)	$ (393,393)
Weighted average assumptions use in measuring obligation at March 31,
	Discount rate		5.75%	6.25%	5.75%	6.25%
	Rate of compensation increase		3.25%	3.25%	N/A*	N/A*
	Expected return on plan assets		8.50%	8.50%	7.88%	8.50%
	Medical trend
		Initial			10.00%	10.00%
		Ultimate			5.00%	5.00%
		Year ultimate rate reached			2008	2007

* Not required for disclosure.
** The dispositions noted in the tables above related to the spin-off of the assets and liabilities in conjunction with the sale of NM Energy.

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

($'s in 000's)			Other Post-retirement Benefits
			2004	2003
Effect of one percentage point change in Health Care Cost Trend rate
	Increase 1%
		Total of Service cost plus interest cost	$ 7,789	$ 6,894
		Post-retirement benefit obligation	107,991	91,180
	Decrease 1%
		Total of Service cost plus interest cost	(6,880)	(6,140)
		Post-retirement benefit obligation	(97,642)	(82,943)

PSC Audit
In August 2003, the New York State PSC approved a settlement with the Company following an audit that identified reconciliation issues between the rate allowance and actual costs of the Company’s pension and other post-retirement benefits. The settlement resolved all issues associated with those obligations for the period prior to its acquisition by National Grid and, among other things, covered the funding of the Company’s pension and post-retirement benefit plans. As part of the settlement, the Company provided $100 million of tax-deductible funding during fiscal 2003 and an additional $209 million of tax-deductible funding by the end of fiscal 2004. Under the settlement, the Group will earn a rate of return of at least 6.60 percent (nominal) on the $209 million of funding through December 31, 2011 and is eligible to earn 80 percent of the amount by which the rate of return on the pension and post-retirement benefit funds exceeds 5.34 per cent (nominal) measured as of that date.

Asset Revaluation
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 during the 60 day period ended March 31, 2002 and the 30 day period ended January 30, 2002 (combined):

($'s in millions)	Charged to Expense	Deferred per Merger Rate Plan	Totals
Pension benefits	$ 25.7	$ 44.0	$ 69.7
Other post-retirement benefits	-	8.6	8.6
	$ 25.7	$ 52.6	$ 78.3

Additional Minimum Pension Liability
The Company has recorded an additional minimum pension liability of approximately $168 million and $269 million at March 31, 2004 and 2003, respectively, for its qualified pension plans because the pension plans’ accumulated benefit obligation was in excess of the prepaid pension asset and accrued pension liability on the balance sheet. While the offset to this entry would normally be a charge after-tax to other comprehensive income, due to the nature of its rate plan the Company has instead recorded a pre-tax regulatory asset.

The Company has also recorded an additional minimum pension liability of approximately $1.5 million at March 31, 2004 for its nonqualified executive pension plan. The non-qualified executive pension plan has no plan assets due to the nature of the plan. The offset to this liability was recorded as a charge to other comprehensive income.

Voluntary Early Retirement Offer
In fiscal 2004, National Grid made a voluntary early retirement offer (VERO) to eligible non-union employees in areas including transmission and corporate administrative functions such as finance, human resources, legal and information technology. A total of 53 employees of the Company accepted the VERO. The majority of them will retire by November 1, 2004, with the remainder retiring by November 1, 2007. The Company expensed approximately $19 million of VERO costs in the fiscal 2004. This amount included approximately $9 million allocated to the Company from National Grid USA Service Company, an affiliate.

Voluntary Early Retirement Program
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 pension net periodic benefit cost tables as Special Termination Benefits at the time of the merger.

Settlement Losses
As the result of the decline in the stock market since the close of the merger with Niagara Mohawk and a reduction in the discount rate applied to pension obligations, the Company has an unrecognized loss in its pension plans. Under SFAS No. 88 “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” (FAS 88), the Company must recognize a portion of this loss immediately when payouts from the plans exceed a certain amount. The Company recognized approximately $22 million in fiscal 2004 relating to the remeasurement of the benefit plans from VERO. The Company had a net settlement loss of approximately $30 million in fiscal 2003 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 approximately $17 million related to the sale of its nuclear assets. In 2001, the Company experienced a net curtailment/settlement loss of $32 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, approximately $11 million is recorded in the deferred loss on the sale of assets, approximately $6 million was due from co-tenants for their allocation of the plant ownership and approximately $15 million was charged to expense.

In February 2004, the Company reached an agreement with PSC Staff that would provide rate recovery for approximately $15 million of the $30 million pension settlement loss incurred in fiscal 2003. This agreement is subject to approval by the full New York State Public Service Commission. In addition, the agreement covers the funding of the entire settlement loss to benefit plan trust funds. Under the agreement, the Company will fund the non-recoverable portion of this loss within 30 days of approval of the agreement. The Company plans to file a petition with the PSC seeking recovery of its fiscal year 2004 settlement losses as well.

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, a postretirement benefit phase-in deferral established in the mid-1990’s, and the offset to the additional minimum pension liability discussed above. 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 2004 and 2003 was approximately $8 million and $17 million, respectively. The phase-in deferral is being amortized at a rate of approximately $3 million per year.

Post-employment benefits
The Company recognizes as an expense the obligation to provide post-employment benefits if the obligation is attributable to employees’ past services, rights to those benefits are vested, payment is probable and the amount of the benefits can be reasonably estimated. At March 31, 2004 and 2003, the Company’s post-employment benefit obligation is approximately $36 million and $34 million, respectively.

Defined contribution plan
The Company also has a defined contribution pension plan (employee savings fund plan) that covers substantially all employees. Employer matching contributions of approximately $7 million, $8 million, $2 million and $10 million were expensed for the twelve months ended March 31, 2004 and 2003, the three months ended March 31, 2002, and the year ended December 31, 2001, respectively.

NOTE I – 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		($'s in 000's)		per share
	March 31,	March 31,	March 31,	March 31,	(Before adding
Series	2004	2003	2004	2003	accumulated dividends)
Preferred $100 par value:
3.40%	57,536	59,960	$ 5,754	$ 5,996	$103.50
3.60%	137,139	138,199	13,714	13,820	104.85
3.90%	94,967	99,817	9,496	9,982	106.00
4.10%	52,830	55,205	5,283	5,520	102.00
4.85%	35,128	37,228	3,513	3,723	102.00
5.25%	34,115	35,839	3,410	3,584	102.00
Preferred $25 par value:
Adjustable Rate -
Series D	503,100	1,113,100	25,155	55,655	50.00 *
Total preferred stock	914,815	1,539,348	$ 66,325	$ 98,280
* Not redeemable prior to December 31, 2004.

During fiscal 2004, 624,533 preferred stock shares were redeemed at a cumulative loss of $939,000 which was charged to additional paid-in capital.

NOTE J – SEGMENTS

The Company’s reportable segments for the years ended March 31, 2004 and 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 amounts 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)
			Electricity -	Electricity -
			Transmission	Distribution	Gas	Corporate	Total
Year ended March 31, 2004
	Operating revenue		$ 255	$ 3,029	$ 780	$ -	$ 4,064
	Operating income before
		income taxes	93	419	68	-	580
	Depreciation and amortization		35	130	36	-	201
	Amortization of stranded costs		-	194	-	-	194
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

(Successor - in millions of dollars)
		Electricity -	Electricity -
		Transmission	Distribution	Gas	Corporate	Total
Goodwill
	Goodwill, at March 31, 2003	$ 303	$ 709	$ 214	$ -	$ 1,226
	Change in goodwill	-	(1)	1	-	-
	Goodwill, at March 31, 2004	$ 303	$ 708	$ 215	$ -	$ 1,226
Total Assets
	At March 31, 2004	$ 1,546	$ 8,809	$ 1,686	$ 375	$ 12,416
	At March 31, 2003	1,512	8,957	1,638	443	12,550

(Successor - in millions of dollars)
			Electricity	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

(Predecessor - in millions of dollars)
			Electricity	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 - unaudited)
			Electricity	Gas	Corporate	Total
Three Months Ended March 31, 2001
	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)
			Electricity	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

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 periods January 1, 2000 through March 31, 2004. 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, 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	-	-	-
Exercised	(411,612)
Outstanding at March 31, 2004	341,268	-	-	-
* 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 years ended March 31, 2004 and 2003, the three months ended March 31, 2002, and the year ended December 31, 2001, is approximately $5 million, $3 million, $21 million, and $12 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. There were no outstanding stock options subsequent to the closing of the merger.

NOTE L – DERIVATIVES AND HEDGING ACTIVITIES

In the normal course of business, the Company is party to derivative financial instruments (derivatives) that are principally used to manage commodity prices 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 activities at risk only to the extent that those activities fall within commodities and financial markets to which it has a physical market exposure in terms and volumes consistent with its core business. The Company does not issue or intend to hold derivative instruments for speculative trading purposes. Derivatives are accounted for in accordance with SFAS 133, which requires derivatives to be reported at fair value as assets or liabilities on the balance sheet. The change in fair value of instruments that qualify for hedge accounting are deferred in Accumulated Other Comprehensive Income and will be reclassified through purchased power or purchased gas expense within the next twelve months. Other instruments are deferred in regulatory assets or liabilities according to current rate agreements and are reclassified through purchased power or gas in the hedge months. The Company’s rate agreements allow for the pass-through of the commodity costs of electricity and natural gas, including the costs of the hedging programs.

The Company has eight indexed swap contracts, expiring in June 2008 that resulted from the master restructuring agreement. There were also three swap contracts from the sale of the Company’s Huntley, Dunkirk, and Albany electric generating stations. The Huntley and Dunkirk contracts expired in June 2003; the Albany contract expired in September 2003. 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, 2004 and 2003, the Company had recorded liabilities at net present value of $715.4 million and $793.0 million, respectively, for these swap contracts and had recorded a corresponding swap contracts regulatory asset. The asset and liability are amortized over the remaining term of the swaps as nominal energy quantities are settled and are adjusted as periodic reassessments are made of energy price forecasts.

At March 31, 2004, the Company projects that it will make the following payments in connection with its swap contracts for the fiscal years 2005 through 2008, subject to changes in market prices and indexing provisions:

	Projected
	Payment
Year Ended	(in thousands
March 31,	of dollars)
2005	$ 182,186
2006	169,578
2007	168,541
2008	159,024
2009	36,038
Total	$ 715,367

The Company uses New York Mercantile Exchange (NYMEX) gas futures to hedge the gas commodity component of its indexed swap contracts. These instruments, as used, do not qualify for hedge accounting status under SFAS 133. Cash flow hedges that qualify under SFAS 133 are as follows: NYMEX gas futures and combination call/put options hedging the purchases of natural gas, NYMEX electric swap contracts hedging the purchases of electricity.

The following table represents the open positions at March 31, 2004 and the results on operations of these instruments for the year ended March 31, 2004.

($'s in 000's)	Balances as of March 31, 2004
Derivative Instrument	Asset*	Regulatory Deferral	Accumulated OCI** , net of tax	Accumulated Deferred Income Tax on OCI**	Year Ended March 31, 2004 Gain/(Loss) Reclass to Commodity Costs
Qualified for Hedge Accounting
NYMEX futures - gas supply	$ 4,089.3	$ -	$ (3,025.0)	$ (2,016.9)	$ (4,229.2)
NYMEX electric swaps - electric supply	$ -	$	$ -	$ -	$ (564.2)
Non-Qualified for Hedge Accounting
NYMEX futures - IPP swaps/non-MRA IPP	$ 20,303.6	$(21,474.2)	$ -	$ -	$ 17,302.0
* Differences between asset and regulatory or other comprehensive income deferral represent contracts settled for the following month.
** Other Comprehensive Income (OCI)

At March 31, 2003, the Company recorded a deferred gain on the futures contracts hedging the IPP swaps and non-MRA IPP of $17.3 million, offset by the consolidated 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. 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.

The gains and losses on the derivatives that are deferred and reported in accumulated other comprehensive income will be reclassified as purchased energy expense in the periods in which expense is impacted by the variability of the cash flows of the hedged item. For the twelve months ended March 31, 2004, the net increase of $4.2 million, shown in the table above, was recorded to gas purchases offset by a corresponding decrease in the cost of a comparable amount of gas. For the twelve months ended March 31, 2004, the realized net loss of $4.2 million from hedging instruments, as shown in the table above, was recorded to gas purchases offset by a corresponding decrease in the cost of a comparable amount of gas. For the twelve months ended March 31, 2003, a net gain 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 purchased energy expense are dependent on future changes in the contract values, the majority of these deferred amounts will be reclassified to expense within the next twelve months. A nominal amount of the hedging instruments extend into April 2005. There were no gains or losses recorded during the year from the discontinuance of gas futures or electric swap cash flow hedges.

There were no open electric swaps at March 31, 2004 or 2003. In April 2003, the Company used NYMEX electric swap contracts to hedge electricity purchases for the summer 2003. The Company continues to evaluate the use of hedging instruments to manage the cost of electricity purchased.

During fiscal 2004, the company allowed all of it gas collars (combination call and put options) to expire. These contracts were hedges of gas supply price risk.

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 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 – ADDITIONAL PAID-IN CAPITAL

The following table details the changes in the equity account, “Additional paid-in capital”

($ in 000's)
March 31, 2002	$ 2,722,894
Return of capital dividend paid to Holdings	(86,086)
Goodwill related adjustments	(16,344)
Net gain on preferred stock tender offers	583
Other	393
March 31, 2003	$ 2,621,440
Equity contribution from Holdings	309,000
Net loss on preferred stock tender offers	(939)
March 31, 2004	$ 2,929,501

The contribution from Holding in fiscal 2004 was for the funding of the pension and post-retirement benefit trusts associated with a PSC settlement (See Note H).

NOTE O – COST OF REMOVAL

In 2001, FASB issued FAS 143. FAS 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. The Company was required to adopt FAS 143 as of April 1, 2003. Retirement obligations associated with long-lived assets included within the scope of FAS 143 are those for which there is a legal obligation under existing or enacted law, statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.

The Company does not have any material asset retirement obligations arising from legal obligations as defined under FAS 143. However, under the Company’s current and prior rate plans it has collected through rates an implied cost of removal for its plant assets. This cost of removal collected from customers differs from the FAS 143 definition of an asset retirement obligation in that these collections are for costs to remove an asset when it is no longer deemed usable (i.e. broken or obsolete) and not necessarily from a legal obligation. For a vast majority of its electric and gas transmission and distribution assets the Company would use these funds to remove the asset so a new one could be installed in its place.

The cost of removal collections from customers has historically been embedded within accumulated depreciation (as these costs have charged over time through depreciation expense). With the adoption of FAS 143 the Company has reclassified these cost of removal collections to a regulatory liability account to more properly reflect the future usage of these collections. The Company estimates it has collected over time approximately $314 million and $307 million for cost of removal through March 31, 2004 and March 31, 2003, respectively.

NOTE P – QUARTERLY FINANCIAL DATA (UNAUDITED)

Operating revenues, operating income, and net income (loss) by quarter from April 1, 2002 through March 31, 2004 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
		Operating	Operating	Net
Quarter Ended		Revenues	Income	Income
March 31,	2004	$ 1,223,922	$ 133,882	$ 62,123
	2003	1,186,061	133,586	37,650
December 31,	2003	959,671	101,860	31,658
	2002	970,278	124,963	37,551
September 30,	2003	930,647	112,228	41,776
	2002	944,339	116,869	22,490
June 30,	2003	949,377	93,625	4,133
	2002	921,243	123,967	28,180

SIGNATURE

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

Date: July 8, 2004	By:	/s/ William F. Edwards
		William F. Edwards President

EXHIBIT INDEX

Exhibit No.	Description
31.1	Certifications of Principal Executive Officer
31.2	Certifications of Principal Financial Officer
32	Certifications Pursuant to 18 U.S.C. 1350