UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X]

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

For the quarterly period ended December 31, 2004

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 No.

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

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 whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

YES [ ]

NO [ X ]

The number of shares outstanding of each of the issuer's classes of common stock, as of February 9, 2005, were as follows:

Registrant	Title	Shares Outstanding

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

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q - For the Quarter Ended December 31, 2004



PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements

		Condensed Consolidated Statements of Operations and Comprehensive Income

		Condensed Consolidated Statements of Retained Earnings

		Condensed Consolidated Balance Sheets

		Condensed Consolidated Statements of Cash Flows

		Notes to Unaudited Condensed Consolidated Financial Statements


Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations

Item 3.	Quantitative and Qualitative Disclosures About Market Risk

Item 4.	Controls and Procedures

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings

Item 2.	Changes in Securities, Use of Proceeds and Issuer of Purchases of Equity Securities

Item 6.	Exhibits and Reports on Form 8-K

Signature

Exhibit Index

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Condensed Consolidated Statements of Operations
(In thousands of dollars)
(UNAUDITED)

				Three Months Ended		Nine Months Ended
				December 31,		December 31,
				2004	2003	2004	2003
Operating revenues:
	Electric			$ 717,812	$ 782,497	$ 2,287,443	$ 2,398,183
	Gas			189,225	177,174	422,700	439,512
			Total operating revenues	907,037	959,671	2,710,143	2,837,695
Operating expenses:
	Purchased energy:
		Electricity purchased		294,447	360,958	1,017,571	1,167,524
		Gas purchased		115,356	97,706	229,415	240,174
	Other operation and maintenance			183,784	227,731	523,889	601,926
	Depreciation and amortization			47,737	49,938	150,955	150,280
	Amortization of stranded costs			61,453	43,517	184,359	130,552
	Other taxes			55,838	54,492	162,344	168,613
	Income taxes			31,811	23,469	105,438	72,913
			Total operating expenses	790,426	857,811	2,373,971	2,531,982
Operating income				116,611	101,860	336,172	305,713
	Other deductions, net			(2,667)	(1,779)	(3,315)	(2,627)
Operating and other income				113,944	100,081	332,857	303,086
Interest:
	Interest on long-term debt			39,111	49,482	130,251	171,955
	Interest on debt to associated companies			17,801	16,083	48,701	39,890
	Other interest			1,515	2,858	7,335	13,674
			Total interest expense	58,427	68,423	186,287	225,519
Net income				$ 55,517	$ 31,658	$ 146,570	$ 77,567
Dividends on preferred stock				841	841	2,522	3,589
Income available to common shareholder				$ 54,676	$ 30,817	$ 144,048	$ 73,978

Condensed Consolidated Statements of Comprehensive Income
(In thousands of dollars)
(UNAUDITED)

				Three Months Ended		Nine Months Ended
				December 31,		December 31,
				2004	2003	2004	2003
Net income				$ 55,517	$ 31,658	$ 146,570	$ 77,567
Other comprehensive income:
	Unrealized gains on securities, net			856	676	696	1,570
	Change in additional minimum pension liability			-	-	-	(1,534)
			Total other comprehensive income	856	676	696	36
Comprehensive income				$ 56,373	$ 32,334	$ 147,266	$ 77,603

Per share data is not relevant because Niagara Mohawk'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
Condensed Consolidated Statements of Retained Earnings
(In thousands of dollars)
(UNAUDITED)

		Three Months Ended		Nine Months Ended
		December 31,		December 31,
		2004	2003	2004	2003
Retained earnings at beginning of period		$ 310,338	$ 128,867	$ 220,966	$ 85,706
	Net income	55,517	31,658	146,570	77,567
	Dividends on preferred stock	(841)	(841)	(2,522)	(3,589)
Retained earnings at end of period		$ 365,014	$ 159,684	$ 365,014	$ 159,684

The accompanying notes are an integral part of these financial statements

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

					December 31,	March 31,
					2004	2004
ASSETS
Utility plant, at original cost:
	Electric plant				$ 5,197,297	$ 5,200,640
	Gas plant				1,481,996	1,477,977
	Common plant				341,702	333,789
	Construction work-in-progress				209,123	152,821
			Total utility plant		7,230,118	7,165,227
	Less: Accumulated depreciation and amortization				2,104,304	2,078,328
			Net utility plant		5,125,814	5,086,899
Goodwill					1,225,742	1,225,742
Pension intangible					10,990	10,990
Other property and investments					57,036	57,273
Current assets:
	Cash and cash equivalents				7,307	26,840
	Restricted cash				48,536	12,163
	Accounts receivable (less reserves of $122,204 and
		$124,200, respectively, and includes receivables
		to associated companies of $11,168 and $516,
		respectively)			537,924	578,654
	Materials and supplies, at average cost:
		Gas storage			85,649	11,226
		Other			15,249	15,714
	Derivative instruments				-	24,393
	Prepaid taxes				31,082	61,769
	Current deferred income taxes				277,428	70,415
	Regulatory asset - swap contracts				170,072	182,000
	Other				10,311	13,389
			Total current assets		1,183,558	996,563
Regulatory and other non-current assets:
	Regulatory assets (Note B):
		Stranded costs			2,835,163	3,019,597
		Swap contracts regulatory asset			408,152	533,367
		Regulatory tax asset			151,117	151,080
		Deferred environmental restoration costs (Note C)			308,000	309,000
		Pension and postretirement benefit plans			484,908	466,789
		Additional minimum pension liability			157,068	157,068
		Loss on reacquired debt			69,079	74,993
		Other			344,553	288,427
			Total regulatory assets		4,758,040	5,000,321
	Other non-current assets				44,543	38,151
			Total regulatory and other non-current assets		4,802,583	5,038,472
				Total assets	$ 12,405,723	$ 12,415,939

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

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

					December 31,	March 31,
					2004	2004
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	2,929,501
		Accumulated other comprehensive income (loss) (Note E)			286	(410)
		Retained earnings			365,014	220,966
			Total common stockholder's equity		3,482,166	3,337,422
	Preferred equity:
		Cumulative preferred stock ($100 par value, optionally redeemable)			41,170	41,170
			Authorized - 3,400,000 shares
			Issued and outstanding - 411,705 shares
		Cumulative preferred stock ($25 par value, optionally redeemable)			-	25,155
		Authorized - 19,600,000 shares
		Issued and outstanding - 0 & 503,100
	Long-term debt				1,723,452	2,273,467
	Long-term debt to affiliates				1,200,000	1,200,000
			Total capitalization		6,446,788	6,877,214
Current liabilities:
	Accounts payable (including payables to associated companies
		of $56,055 and $42,485, respectively)			294,542	285,965
	Customers' deposits				26,013	26,133
	Accrued interest				45,896	98,221
	Short-term debt to affiliates				704,500	463,500
	Current portion of swap contracts				170,072	182,000
	Current portion of long-term debt				550,420	532,620
	Other				129,632	125,461
		Total current liabilities			1,921,075	1,713,900
Other non-current liabilities:
	Accumulated deferred income taxes				1,629,805	1,346,938
	Liability for swap contracts				408,152	533,367
	Employee pension and other benefits				426,738	449,803
	Additional minimum pension liability				169,615	169,615
	Liability for environmental remediation costs (Note C)				308,000	309,000
	Nuclear fuel disposal costs				144,723	143,265
	Cost of removal regulatory liability				317,642	313,545
	Other				633,185	559,292
		Total other non-current liabilities			4,037,860	3,824,825

	Commitments and contingencies (Notes B and C)				-	-

				Total capitalization and liabilities	$ 12,405,723	$ 12,415,939

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

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Condensed Consolidated Statements of Cash Flows

(In thousands of dollars)

(UNAUDITED)

Nine Months ended December 31,

2004

2003

Operating activities:

Net income

$ 146,570

$ 77,567

Adjustments to reconcile net income to net cash

provided by (used in) operating activities:

Depreciation and amortization

150,955

150,280

Amortization of stranded costs

184,359

130,552

Provision for deferred income taxes

77,901

45,765

Cash paid to pension and postretirement benefit plan trusts

(89,751)

(250,896)

Other changes in pension and postretirement benefits

70,012

71,111

Changes in operating assets and liabilities:

Decrease in accounts receivable, net

40,730

10,701

Increase in materials and supplies

(73,958)

(74,624)

Increase (decrease) in accounts payable and accrued expenses

4,746

(52,196)

Decrease in accrued interest and taxes

(52,325)

(54,795)

Other, net

63,131

(38,280)

Net cash provided by operating activities

522,370

15,185

Investing activities:

Construction additions

(189,551)

(228,954)

Change in restricted cash

(36,373)

(6,173)

Other investments

316

13,725

Other

3,002

(12,347)

Net cash used in investing activities

(222,606)

(233,749)

Financing activities:

Dividends paid on preferred stock

(2,522)

(3,589)

Reductions in long-term debt

(532,620)

(1,273,890)

Proceeds from long-term debt to affiliates

700,000

Redemption of preferred stock

(25,155)

(33,903)

Net change in short-term debt to affiliates

241,000

503,600

Equity contribution from parent

309,000

Net cash provided by (used in) financing activities

(319,297)

201,218

Net decrease in cash and cash equivalents

(19,533)

(17,346)

Cash and cash equivalents, beginning of period

26,840

30,038

Cash and cash equivalents, end of period

$ 7,307

$ 12,692

Supplemental disclosures of cash flow information:

Interest paid

$ 233,520

$ 274,921

Income taxes paid

$ 10,642

$ 15,372

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

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Notes to Unaudited Condensed Consolidated Financial Statements

NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation: Niagara Mohawk Power Corporation and subsidiary companies (the Company), in the opinion of management, have included all adjustments (which include normal recurring adjustments) necessary for a fair statement of the financial position and results of operations for the interim periods presented. The March 31, 2004 condensed balance sheet data included in this quarterly report on Form 10-Q was derived from audited financial statements included in the Company's Annual Report on Form 10-K for the year ended March 31, 2004. As such, the March 31, 2004 balance sheet included in this Form 10-Q is considered unaudited as it does not include all the footnote disclosures contained in the Company's Form 10-K. These financial statements and the notes thereto should be read in conjunction with the audited financial statements included in the Company's Annual Report on Form 10-K for the year ended March 31, 2004.

The Company's electric sales tend to be substantially higher in summer and winter months as related to weather patterns in its service territory; gas sales tend to peak in the winter. Notwithstanding other factors, the Company's quarterly net income will generally fluctuate accordingly. Therefore, the earnings for the three-month and nine-month period ended December 31, 2004 should not be taken as an indication of earnings for all or any part of the balance of the year.

The Company is a wholly owned subsidiary of Niagara Mohawk Holdings, Inc. (Holdings) and, indirectly, National Grid Transco plc.

Reclassifications: Certain amounts from prior years have been reclassified in the accompanying consolidated financial statements to conform to the current year presentation.

NOTE B - RATE AND REGULATORY ISSUES

The Company's financial statements conform to generally accepted accounting principles in the United States of America (GAAP), including the accounting principles for rate-regulated entities with respect to its regulated operations. Statement of Financial Accounting Standards 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 and revenues which would otherwise be charged to expense or revenues, 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 $4.9 billion and $5.2 billion at December 31, 2004 and March 31, 2004, 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.

NOTE C - COMMITMENTS AND CONTINGENCIES

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 approximately 100 sites with which it may be associated, including approximately 50 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 of $308 million and $309 million which is reflected in the Company's Condensed Consolidated Balance Sheets at December 31, 2004 and March 31, 2004, respectively. The potential high end of the range is presently estimated at approximately $535 million. The total net reserve has decreased by $1 million since March 31, 2004 primarily due to $17 million in regular spending offset by an additional $9 million accrual for anticipated remediation costs and an additional $7 million accrual for soil removal associated with manufactured gas plant sites.

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.

Market Pricing: The U.S. Court of Appeals for the District of Columbia Circuit rendered a decision on March 16, 2004 finding that FERC failed to explain its rationale supporting its decision to approve a NYISO action invoking its authority through its "Temporary Extraordinary Procedures" to lower prices retroactively in the New York electricity market, based on NYISO's determination that a market design flaw existed that had caused unusually high prices in that market on two days in May 2000. The court remanded to FERC for further explanation of its decision to uphold NYISO's actions. If the FERC determines on remand that the prices should not have been adjusted by NYISO, New York State transmission owners, including the Company, would face additional expense due to the reinstatement of the higher market prices. The remand to FERC is pending and the Company cannot predict the outcome of this proceeding.

Legal matters:
FERC Refund Order. Niagara Mohawk made filings with the FERC in 2001 and 2002 reporting on the amounts of refunds that were due to certain customers in compliance with prior FERC orders. A group consisting of many of Niagara Mohawk's largest commercial and industrial customers (the Multiple Intervenors) had intervened in the cases and challenged the refund reports. On December 21, 2004, the Company reached a settlement with the Multiple Intervenors under which it will refund $1.15 million, subject to approval by the FERC.

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 involved in several proceedings with the NRG Affiliates to recover bills for station service rendered to the Plants. The most significant is the proceeding at FERC involving Niagara Mohawk's complaint against the NRG Affiliates for failure to pay station service charges the Company assessed under its state-approved retail tariffs. The other proceedings have all been stayed pending the outcome of the FERC proceeding. As of December 31, 2004, the NRG Affiliates owed the Company approximately $42 million for station service. On November 19, 2004, the FERC issued an order denying Niagara Mohawk's complaint and found that the NRG Affiliates do not have to pay state-approved retail rates for station service. Niagara Mohawk has petitioned the FERC for a rehearing of its order. See the Retail Bypass discussion below for more information.

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 NRG's 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. Without admitting any liability, on January 11, 2005, the Company and the State asked the Court to approve a settlement of the claims filed against the Company. At the same time, the State and the NRG companies asked the Court to approve their own separate settlement. If approved, both settlements will fully resolve all claims asserted in this litigation against all parties. The Company does not expect a material impact on the results of operation for the quarter ending March 31, 2005.

Retail Bypass: As discussed in more detail in the Company's Form 10-K for the fiscal year ended March 31, 2004, a number of generators have complained or withheld payments associated with the Company's delivery of station service to their generation facilities, arguing that they should be permitted to bypass the Company's retail charges. The FERC issued two orders on complaints filed by station service customers of the Company in December 2003, allowing two generators to net their station service electricity over a 30-day period and to avoid state-authorized charges for deliveries made over distribution facilities. A third order involving the NRG Affiliates is discussed above under the caption Niagara Mohawk Power Corp. v. Huntley Power et al. These orders directly conflict with the Company's state-approved tariffs and the orders of the PSC on station service rates. The December 2003 FERC orders, if upheld, will permit these generators to bypass the Company's state-jurisdictional station service charges for electricity, including those set forth in the filing that was approved by the PSC on November 25, 2003. The Company filed for rehearing of these orders, and the FERC denied these requests in January 2005. The Company intends to appeal the December 2003 and January 2005 orders to the U.S. Court of Appeals for the District of Columbia Circuit.

In an order dated May 10, 2004, in a related proceeding concerning the NYISO, the FERC reaffirmed its reasoning of the December 2003 orders. In so ruling, the FERC indicated that the NYISO station service order 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 that do not compete with incumbent utilities for customer load. The Company appealed the order to the Court of Appeals for the District of Columbia Circuit on July 9, 2004.

These recent FERC 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 D - SEGMENT INFORMATION

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

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

Three Months Ended December 31, 2004
	Operating revenue		$ 63	$ 655	$ 189	$ 907
	Operating income before
		income taxes	25	98	25	148
	Depreciation and amortization		9	30	9	48
	Amortization of stranded costs		-	61	-	61

Three Months Ended December 31, 2003
	Operating revenue		$ 64	$ 719	$ 177	$ 960
	Operating income before
		income taxes	21	86	18	125
	Depreciation and amortization		9	32	9	50
	Amortization of stranded costs		-	44	-	44

Nine Months Ended December 31, 2004
	Operating revenue		$ 191	$ 2,096	$ 423	$ 2,710
	Operating income before
		income taxes	79	313	50	442
	Depreciation and amortization		26	97	28	151
	Amortization of stranded costs		-	184	-	184

Nine Months Ended December 31, 2003
	Operating revenue		$ 191	$ 2,207	$ 440	$ 2,838
	Operating income before
		income taxes	70	283	26	379
	Depreciation and amortization		26	97	27	150
	Amortization of stranded costs		-	131	-	131

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

December 31, 2004
	Goodwill	$ 303	$ 708	$ 215	$ -	$ 1,226
	Total assets	$ 1,542	$ 8,431	$ 1,821	$ 612	$ 12,406


March 31, 2004
	Goodwill	$ 303	$ 708	$ 215	$ -	$ 1,226
	Total assets	$ 1,546	$ 8,809	$ 1,686	$ 375	$ 12,416

NOTE E - ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)


				Unrealized		Total
				Gains and	Minimum	Accumulated
			(in 000's)	Losses on	Pension	Other
				Available-for-	Liability	Comprehensive
				Sale Securities	Adjustment	Income (Loss)
March 31, 2004				$ 1,147	$ (1,557)	$ (410)
	Unrealized gains on securities,
		net of taxes		696		696
December 31, 2004				$ 1,843	$ (1,557)	$ 286

The deferred tax benefit (expense) on other comprehensive income for the following periods was (in thousands of dollars):

	For the Nine Months Ended December 31,
	2004	2003
Unrealized gain/(losses) on securities	$ (464)	$ (1,047)

NOTE F - EMPLOYEE BENEFITS

As discussed in the Company's Annual Report on Form 10-K for the year ended March 31, 2004, the Company provides benefits to retirees in the form of pension and other postretirement benefits. The qualified defined benefit pension plan covers substantially all employees meeting certain minimum age and service requirements. Funding for the qualified defined benefit pension plans is based on actuarially determined contributions, the maximum of which is generally the amount deductible for income tax purposes and the minimum being that required by the Employee Retirement Income Security Act of 1974, as amended. The pension plans' assets primarily consist of investments in equity and debt securities. In addition, the Company sponsors a non-qualified plan (a plan that does not meet the criteria for tax benefits) that covers officers, certain other key employees, and non-employee directors. The Company provides certain health care and life insurance benefits to retired U.S. employees and their eligible dependents. These benefits are subject to minimum age and service requirements. The health care benefits include medical coverage, dental coverage, and prescription drug coverage and are subject to certain limitations, such as deductibles and co-payments.

Benefit plans' costs charged to the Company during the three and nine months ended December 31, 2004 and 2003 included the following components:


			Other Postretirement
($'s in 000's)	Pension Benefits		Benefits
For the Three Months Ended December 31,	2004	2003	2004	2003

Service cost	$ 6,745	$ 6,447	$ 3,309	$ 1,905
Interest cost	17,153	18,078	15,638	14,244
Expected return on plans' assets	(16,127)	(17,235)	(11,245)	(8,582)
Amortization of prior service cost	796	280	2,411	-
Recognized actuarial loss	6,172	4,352	5,417	5,645
Net periodic benefit cost	14,739	11,922	15,530	13,212

Special Termination Benefits	-	9,957	-	400
Settlement Expense	-	19,486	-	-


			Other Postretirement
($'s in 000's)	Pension Benefits		Benefits
For the Nine Months Ended December 31,	2004	2003	2004	2003

Service cost	$ 19,664	$ 19,341	$ 7,472	$ 5,714
Interest cost	50,918	54,232	44,849	42,731
Expected return on plans' assets	(48,592)	(51,704)	(34,123)	(25,745)
Amortization of prior service cost	1,351	840	2,287	-
Recognized actuarial loss	18,832	13,056	17,944	16,935
Net periodic benefit cost	42,173	35,765	38,429	39,635

Special Termination Benefits	185	9,957	-	400
Settlement Expense	-	19,486	-	-


Estimated contributions for this year	$ 80,000	N/A	$ 25,000	N/A

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FORWARD-LOOKING INFORMATION

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

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

(b) the impact of general economic changes in New York;

(c) federal and state regulatory developments and changes in law, including those governing municipalization and exit fees;

(d) federal regulatory developments concerning regional transmission organizations;

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

(f) timing and adequacy of rate relief;

(g) adverse changes in electric load;

(h) acts of terrorism;

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

(j) failure to recover costs currently deferred under the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulations", as amended, and the Merger Rate Plan in effect with the New York State Public Service Commission (PSC).

CRITICAL ACCOUNTING POLICIES

Certain critical accounting policies are based on assumptions and conditions that, if changed, could have a material effect on the financial condition, results of operations and liquidity of the Company. See the Company's Annual Report on Form 10-K for the period ended March 31, 2004, Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - "Critical Accounting Policies" for a detailed discussion of these policies.

RESULTS OF OPERATIONS

EARNINGS

Net income for the three months ended December 31, 2004 increased by approximately $24 million from the comparable period in the prior year. The increase is primarily due to decreased retiree benefit expense of $39 million relating to one-time items, lower interest costs of approximately $10 million, and other savings of $7 million due in part to merger related integration. These savings were mostly offset by a decrease in electric margin of $16 million (revenue, less the cost of purchased electricity, amortization of stranded costs and gross receipts tax), an increase in income taxes of $8 million, a decrease in gas margin of $6 million (revenue, less the cost of purchased gas and gross receipts tax), and a decrease in other income and deductions of $1 million.

Net income for the nine months ended December 31, 2004 increased by approximately $69 million from the comparable period in the prior year. The increase is primarily due to lower interest costs of approximately $39 million, decreased retiree benefit expense of $53 million relating to one-time items, reduced bad debt expense of $19 million and other savings of $7 million due in part to merger related integration. These savings were mostly offset by decreased electric margin of $11 million, an increase in income taxes of $33 million, a decrease in gas margin of $3 million and a decrease in other income and deductions of $1 million.

REVENUES

Electric revenues decreased approximately $65 million and $111 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. The table below details components of this fluctuation.

Period ended December 31, 2004
(In millions of dollars)

			Three Months	Nine Months

	Retail sales		$ (24)	$ (68)
	Sales for resale		(41)	(43)
		Total	$ (65)	$ (111)

The decrease in revenue is primarily due to lower purchase power costs being recovered (see decrease in purchased electricity below) offset by higher stranded cost revenues.

Gas revenues increased by $12 million and decreased by $17 million in the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. The increase for the three months ended December 31, 2004 is primarily a result of higher gas commodity prices passed through to customers. The decrease for the nine months ended December 31, 2004 can be attributed primarily to a decrease in the cost of purchased gas due to decreased volumes of gas purchased, as a result of milder weather in fiscal 2005 compared to the prior year. The table below details components of this fluctuation.

Period ended December 31, 2004
(In millions of dollars)

			Three Months	Nine Months

	Cost of purchased gas		$ 18	$ (11)
	Delivery revenue		(5)	(3)
	Other		(1)	(3)
		Total	$ 12	$ (17)

The volume of gas sold for the three months ended December 31, 2004, excluding transportation of customer-owned gas decreased 1.320 million Dekatherms (Dth) which was a 9.0 percent decrease from the comparable period in the prior year. The decrease is a result of lower overall demand due partly to milder weather and partly to a lower number of days counted in the fiscal 2005 period, as a result of differences in the Company's meter reading schedule.

The volume of gas sold for the nine months ended December 31, 2004, excluding transportation of customer-owned gas decreased 3.087 million Dth which was a 9.7 percent decrease from the comparable period in the prior year. The decrease is a result of lower overall demand primarily due to milder weather.

OPERATING EXPENSES

Purchased electricity decreased approximately $67 million and $150 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. The volume of kWh purchased for the three and nine months ended December 31, 2004 decreased 1.9 billion kWh (23%) and 3.4 billion kWh (14%), respectively, as compared to the comparable periods in the prior year. This volume decrease was offset by a 6% and 1% increase in the price of electricity for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. These costs do not impact electric margin or net income as the Company's rate plans allow full recoverability of these costs from customers.

Purchased gas expense increased approximately $18 million and decreased approximately $11 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. Contributing to the increase of $18 million in the three months ended December 31, 2004 was an increase in gas costs of $23 million which was partially offset by a decrease in volumes purchased of $5 million. Contributing to the decrease of $11 million for the nine months ended December 31, 2004 was an $18 million decrease in volumes purchased, partially offset by an increase in gas prices of $7 million. These costs do not impact gas margin or net income as the Company's rate plans allow full recoverability of these costs from customers.

Other operation and maintenance expense decreased approximately $44 million and $78 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. The table below details components of this fluctuation.

(In millions of dollars)

	Three Months	Nine Months
Decreased bad debt expense	$ (1)	$ (19)
Recovery of fiscal 2003 Pension settlement loss	-	(14)
Loss on the sale of facilities	3	7
Fiscal 2004 Pension settlement loss	(20)	(20)
Fiscal 2004 Non-union VERO	(19)	(19)
April 2003 ice storm	-	(6)
Other	(7)	(7)
Total	$ (44)	$ (78)

The reduction in bad debt expense for the three and nine months ended December 31, 2004 was mainly the result of a decrease in accounts receivable and improved collection practices.

The pension settlement loss recovery of $14 million reflects the PSC July 2004 approval for the Company to recover a portion of the $30 million pension settlement loss incurred in fiscal 2003. The Company has petitioned the PSC for recovery of a $21 million pension settlement loss, of which it recorded $20 million to expense in the third quarter of fiscal 2004. In fiscal 2004, the Company recorded a $19 million loss related to the non-union employee early retirement program (VERO). These pension items were recorded to expense by the Company, without a similar adjustment in the comparison period.

As part of the Company's ongoing cost savings initiative in connection with its integration with National Grid USA, the Company completed the sale of three buildings in the current fiscal year. These sales resulted in a charge of approximately $7 million (pre-tax) to expense to reflect the Company's share of its unrecovered cost of these facilities, in accordance with the PSC's orders on these matters. Other expense for the three and nine months ended December 31, 2004 as compared to the same period in the prior year, reflects ongoing reduced costs from merger-related efficiencies.

Amortization of stranded costs increased approximately $18 million and $54 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year in accordance with the Merger Rate Plan. The stranded investment balance is being amortized unevenly over the term of the Merger Rate Plan, from January 1, 2002 to December 31, 2011, at increasing levels in later years. The increases in the amortization of stranded costs are included in the Company rate plan and does not impact net income.

Other taxes increased approximately $1 million and decreased approximately $6 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. The nine month period decrease is primarily due to a reduction in gross receipts tax (GRT) due to lower rates and reduced revenues.

Income taxes increased approximately $8 million and $33 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year, primarily due to higher recorded book income. Also, in the nine months ended December 31, 2003, there was a $9 million adjustment to taxes which increased income tax expense for which there was no comparable charge in the current period.

NON OPERATING EXPENSES

Interest charges decreased $10 million and $39 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. The decrease in interest charges is attributable not only to the repayment of third-party debt using affiliated company debt at lower interest rates but also the refinancing of long-term tax exempt debt from fixed to floating rates. The expiration of the Master Restructuring Agreement interest savings deferral in the second quarter of fiscal 2004 (which had been amortizing an overcollection of pre-merger interest costs) also contributed to the decrease for the period.

LIQUIDITY AND CAPITAL RESOURCES

See the Company's Annual Report on Form 10-K for the period ended March 31, 2004, Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - "Financial Position, Liquidity and Capital Resources".

Short-Term. At December 31, 2004, the Company's principal sources of liquidity included cash and cash equivalents of $7 million and accounts receivable of $538 million. The Company has a negative working capital balance of $738 million primarily due to short-term debt to affiliates of $705 million. As discussed below, the Company believes it has sufficient cash flow and borrowing capacity to fund such deficits as necessary in the near term.

Net cash provided by operating activities increased approximately $507 million for the nine months ended December 31, 2004 from the comparable period in the prior year. The primary reasons for the increase in operating cash flow are:

Lower cash payments for purchased gas. This is primarily due to higher purchased gas costs incurred in March 2003 that resulted in a large purchased gas payable (included in accounts payable) at March 31, 2003. This caused a larger than normal cash outflow during the nine months ended December 31, 2003 when the payables came due.
Increased net income (see earnings discussion above) of approximately $69 million.
Increased stranded cost revenues for the return of previously incurred stranded costs of approximately $54 million. Stranded cost revenues are included in electric revenue and include a "recovery of" and a "return on" the Company's Stranded Cost regulatory asset. The cash inflow from the "return on" stranded costs is included in net income. The cash inflow from the "recovery of" stranded costs is offset by stranded cost amortization (a non-cash expense, see "Amortization of Stranded Costs" above) and has no effect on net income.
Increased provision for deferred income taxes of approximately $32 million. This was mainly attributable to utilization of net operating loss carryforwards. For the nine months ended December 31, 2003, there was no net operating loss carryforward utilization.
$160 million increase due to a decline in required funding of employee pension and other benefits.

Net cash used in investing activities decreased by approximately $11 million for the nine months ended December 31, 2004 from the comparable period in the prior year. The decrease was primarily due to a decrease in construction additions of $39 million, attributable to more capital expenditures incurred in fiscal 2004 related to the construction of a new gas pipeline and the installation of automatic meter reading devices in the Company's service territory. This decrease is offset by an increase in restricted cash of $30 million, mainly due to margin funding for hedging activities.

National Grid USA and certain subsidiaries, including the Company, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. The Company has regulatory approval to issue up to $1 billion of short-term debt. 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. An additional $521 million of cash was used in financing activities for the nine months ended December 31, 2004 from the comparable period in the prior year. This increase is primarily due to the receipt of $700 million of proceeds from a related party note in the prior period used to fund early redemptions of higher interest rate third party debt and to reduce borrowing under the intercompany money pool. In fiscal 2004, the Company received a $309 million contribution from its parent company. There were no similar receipts in the current period. The Company reduced its short-term debt to affiliates by $263 million in the nine months ended December 31, 2004 from the comparable period in the prior year. The change in receipts is offset by a decrease in reductions in long-term debt of $741 million.

On May 27, 2004, the Company completed the refinancing of $115.7 million of tax exempt bonds, 7.2%, due 2029. The new bonds were initially issued in auction rate mode.

On December 31, 2004, the Company redeemed all outstanding Cumulative Fixed/Adjustable Rate Series D Preferred Stock for $25 million.

Long-Term Liquidity. The Company's total capital requirements consist of amounts for its construction program, working capital needs, and maturing debt issues. See the Company's Annual Report on Form 10-K for the fiscal year ended March 31, 2004, Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - "Financial Position, Liquidity and Capital Resources" for further information on long-term commitments.

OTHER REGULATORY MATTERS

Elevated equipment voltage. The PSC issued an order on January 5, 2005, requiring all electric utilities in the state to test annually all of their publicly accessible transmission and distribution facilities for elevated equipment voltage and perform visual inspections of all facilities on a five year schedule. As anticipated in the July 2004 order proposing the guidelines, the order contains strict compliance requirements and potential financial penalties for failure to achieve testing and inspection targets. Failure to meet the annual target for performing tests will result in a 0.75% reduction in return on equity, as will failure to meet the annual target for inspections. The costs to comply with this order are expected to be significant. Under its existing rate plan, the Company is eligible to recover through rates that portion of its costs that the PSC considers incremental. The Company, together with other utilities, has filed for rehearing on certain aspects of this order, including a request for more time to test remote areas of the service territory, a challenge to the PSC authority to impose penalties for non-compliance, and clarification that the PSC did not intend to impose a different standard for cost recovery for these programs than is otherwise specified in the Company's pre-existing rate plan, among other clarifications.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Interest Rate Risk: The Company's major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable rate debt. At December 31, 2004, the Company's tax exempt variable rate long-term debt had a carrying value of approximately $575 million. While the ultimate maturity dates of the underlying loan agreements range from 2013 to 2029, this debt is issued in auction rate mode. The various components that comprise this debt are currently issued for periods of 7 days, 35 days, and 90 days, and are remarketed through agents at the end of each period. The weighted average rate, including a 0.25% remarketing fee, for the quarter and the nine months ended December 31, 2004, were approximately 1.88% and 1.55%, respectively.

There were no material changes in the Company's market risk or market risk strategies during the nine months ended December 31, 2004. For a detailed discussion of market risk, see the Company's Annual Report on Form 10-K for fiscal year ended March 31, 2004, Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

ITEM 4. CONTROLS AND PROCEDURES

The Company has carried out an evaluation under the supervision and with the participation of its management, including the Chief Financial Officer and President, of the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report.

Based on that evaluation, it was determined that these disclosure controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports that the Company files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required.

No change in internal control over financial reporting occurred during the fiscal quarter ended December 31, 2004 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

New York State v. Niagara Mohawk Power Corp. et al.: As described in the Company's 10-K for the fiscal year ended March 31, 2004, the New York State Attorney General had filed a civil action against the Company, NRG Energy, Inc. and certain of NRG's 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. Without admitting any liability, on January 11, 2005, the Company and the State asked the Court to approve a settlement of the claims filed against the Company. At the same time, the State and the NRG companies asked the Court to approve their own separate settlement. If approved, both settlements will fully resolve all claims asserted in this litigation against all parties.

ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES

ISSUER PURCHASES OF EQUITY SECURITIES -
CUMULATIVE FIXED/ADJUSTABLE RATE SERIES D PREFERRED STOCK

Period	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share	(c) Total Number of Shares Purchased as Part of Publicly Announced Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
October 1-31, 2004
November 1-30, 2004
December 1-31, 2004	503,100(i)	$50	-0-	-0-
Total	503,100	$50	-0-	-0-

(i) Redeemed at the Company's option in accordance with the terms of the Cumulative Fixed/Adjustable Rate Series D Preferred Stock.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)	Exhibits

	The exhibit index is incorporated herein by reference.

(b)	Reports on Form 8-K

	The Company did not file any reports on Form 8-K during the fiscal quarter ended December 31, 2004.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report on Form 10-Q for the quarter ended December 31, 2004 to be signed on its behalf by the undersigned thereunto duly authorized.

	NIAGARA MOHAWK POWER CORPORATION


Date: February 14, 2005	By	/s/ Edward A. Capomacchio Edward A. Capomacchio Authorized Officer and Controller and Principal Accounting Officer

EXHIBIT INDEX

Exhibit Number	Description

31.1	Certification of Principal Executive Officer pursuant to Rule 13a-14(a)

31.2	Certification of Principal Financial Officer pursuant to Rule 13a-14(a)

32	Section 1350 Certifications

NIAGARA MOHAWK POWER CORP /NY/ 10-Q