Niagara Mohawk Power (NMKBP) 10-Q 2005 Q2 Quarterly report

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 September 30, 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 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 November 10, 2004, 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 September 30, 2004

			PAGE
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 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		Six Months Ended
				September 30,		September 30,
				2004	2003	2004	2003
Operating revenues:
	Electric			$ 833,698	$ 856,286	$ 1,569,632	$ 1,617,686
	Gas			79,170	74,361	233,475	262,338
			Total operating revenues	912,868	930,647	1,803,107	1,880,024
Operating expenses:
	Purchased energy:
		Electricity purchased		389,419	421,977	723,124	806,566
		Gas purchased		30,820	25,994	114,059	142,468
	Other operation and maintenance			168,055	191,209	340,105	374,195
	Depreciation and amortization			52,532	49,590	103,218	100,342
	Amortization of stranded costs			61,453	43,518	122,906	87,035
	Other taxes			53,128	56,381	106,506	114,121
	Income taxes			42,513	29,750	73,627	49,444
			Total operating expenses	797,920	818,419	1,583,545	1,674,171
Operating income				114,948	112,228	219,562	205,853
	Other income (deduction), net			(3,397)	801	(649)	(2,848)
Operating and other income				111,551	113,029	218,913	203,005
Interest:
	Interest on long-term debt			42,804	51,696	91,140	122,473
	Interest on debt to associated companies			15,822	15,344	30,900	23,807
	Other interest			2,707	4,213	5,820	10,816
			Total interest expense	61,333	71,253	127,860	157,096
Net income				$ 50,218	$ 41,776	$ 91,053	$ 45,909
Dividends on preferred stock				840	1,370	1,681	2,748
Income available to common shareholder				$ 49,378	$ 40,406	$ 89,372	$ 43,161
Condensed Consolidated Statements of Comprehensive Income
(In thousands of dollars)
(UNAUDITED)
				Three Months Ended		Six Months Ended
				September 30,		September 30,
				2004	2003	2004	2003
Net income				$ 50,218	$ 41,776	$ 91,053	$ 45,909
Other comprehensive income (loss):
	Unrealized (losses) gains on securities, net			(105)	206	(160)	894
	Change in additional minimum pension liability			-	-	-	(1,534)
			Total other comprehensive income (loss)	(105)	206	(160)	(640)
Comprehensive income				$ 50,113	$ 41,982	$ 90,893	$ 45,269

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		Six Months Ended
		September 30,		September 30,
		2004	2003	2004	2003
Retained earnings at beginning of period		$ 260,960	$ 88,461	$ 220,966	$ 85,706
	Net income	50,218	41,776	91,053	45,909
	Dividends on preferred stock	(840)	(1,370)	(1,681)	(2,748)
Retained earnings at end of period		$ 310,338	$ 128,867	$ 310,338	$ 128,867

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)
					September 30,	March 31,
					2004	2004
ASSETS
Utility plant, at original cost:
	Electric plant				$ 5,239,739	$ 5,200,640
	Gas plant				1,477,576	1,477,977
	Common Plant				340,441	333,789
	Construction work-in-progress				177,822	152,821
			Total utility plant		7,235,578	7,165,227
	Less: Accumulated depreciation and amortization				2,129,056	2,078,328
			Net utility plant		5,106,522	5,086,899
Goodwill					1,225,742	1,225,742
Pension intangible					10,990	10,990
Other property and investments					55,977	57,273
Current assets:
	Cash and cash equivalents				16,040	26,840
	Restricted cash				2,786	12,163
	Accounts receivable (less reserves of $117,169 and
		$124,200, respectively, and includes receivables
		to associated companies of $15,712 and $516,
		respectively)			518,427	578,654
	Materials and supplies, at average cost:
		Gas storage			101,635	11,226
		Other			19,173	15,714
	Derivative instruments				54,903	24,393
	Prepaid taxes				67,586	61,769
	Current deferred income taxes				80,450	70,415
	Regulatory asset - swap contracts				187,475	182,000
	Other				19,918	13,389
			Total current assets		1,068,393	996,563
Regulatory and other non-current assets:
	Regulatory assets (Note B):
		Stranded costs			2,896,614	3,019,597
		Swap contracts regulatory asset			507,632	533,367
		Regulatory tax asset			151,018	151,080
		Deferred environmental restoration costs (Note C)			310,000	309,000
		Pension and postretirement benefit plans			475,029	466,789
		Additional minimum pension liability			157,068	157,068
		Loss on reacquired debt			71,037	74,993
		Other			340,225	288,427
			Total regulatory assets		4,908,623	5,000,321
	Other non-current assets				47,391	38,151
			Total regulatory and other non-current assets		4,956,014	5,038,472
				Total assets	$ 12,423,638	$ 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)
					September 30,	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)			(570)	(410)
		Retained earnings			310,338	220,966
			Total common stockholder's equity		3,426,634	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	25,155
			Authorized - 19,600,000 shares
			Issued and outstanding - 503,100 shares
	Long-term debt				2,163,755	2,273,467
	Long-term debt to affiliates				1,200,000	1,200,000
			Total capitalization		6,856,714	6,877,214
Current liabilities:
	Accounts payable (including payables to associated companies				327,660	285,965
		of $39,844 and $42,485, respectively)
	Customers' deposits				24,929	26,133
	Accrued interest				90,501	98,221
	Short-term debt to affiliates				467,000	463,500
	Current portion of swap contracts				187,475	182,000
	Current portion of long-term debt				410,240	532,620
	Other				115,762	125,461
		Total current liabilities			1,623,567	1,713,900
Other non-current liabilities:
	Accumulated deferred income taxes				1,400,734	1,346,938
	Liability for swap contracts				507,632	533,367
	Employee pension and other benefits				415,454	449,803
	Additional minimum pension liability				169,615	169,615
	Liability for environmental remediation costs (Note C)				310,000	309,000
	Nuclear fuel disposal costs				144,105	143,265
	Cost of removal regulatory liability				315,273	313,545
	Other				680,544	559,292
		Total other non-current liabilities			3,943,357	3,824,825
	Commitments and contingencies (Notes B and C)				-	-
				Total capitalization and liabilities	$ 12,423,638	$ 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)
					Six Months ended September 30,
					2004	2003
Operating activities:
	Net income				$ 91,053	$ 45,909
	Adjustments to reconcile net income to net cash
			provided by (used in) operating activities:
		Depreciation and amortization			103,218	100,342
		Amortization of stranded costs			122,906	87,035
		Provision for deferred income taxes			51,043	24,368
		Changes in operating assets and liabilities:
			Decrease in accounts receivable, net		60,227	67,854
			Increase in materials and supplies		(93,868)	(81,400)
			Increase (decrease) in accounts payable and accrued expenses		30,792	(43,603)
			Decrease in accrued interest and taxes		(7,720)	(10,034)
			Decrease in employee pension and other benefits		(25,457)	(174,443)
			Other, net		(1,529)	(20,344)
				Net cash provided by (used in) operating activities	330,665	(4,316)
Investing activities:
	Construction additions				(120,854)	(153,837)
	Change in restricted cash				9,377	(33,840)
	Other investments				1,285	13,472
	Other				(712)	(8,778)
				Net cash used in investing activities	(110,904)	(182,983)
Financing activities:
	Dividends paid on preferred stock				(1,681)	(2,748)
	Reductions in long-term debt				(232,380)	(1,269,176)
	Proceeds from long-term debt to affiliates				-	700,000
	Redemption of preferred stock				-	(31,800)
	Net change in short-term debt to affiliates				3,500	474,500
	Equity contribution from parent				-	309,000
	Other				-	(1,989)
				Net cash provided by (used in) financing activities	(230,561)	177,787
Net increase (decrease) in cash and cash equivalents					(10,800)	(9,512)
Cash and cash equivalents, beginning of period					26,840	30,038
Cash and cash equivalents, end of period					$ 16,040	$ 20,526
Supplemental disclosures of cash flow information:
	Interest paid				$ 136,256	$ 157,049
	Income taxes paid				$ 7,823	$ 9,993

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 six-month period ended September 30, 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.

New Accounting Standards: On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act expands Medicare, primarily by adding a prescription drug benefit for Medicare-eligibles starting in 2006. The Act provides employers currently sponsoring prescription drug programs for Medicare-eligibles with a range of options for coordinating with the new government-sponsored program to potentially reduce program cost. These options include supplementing the government program on a secondary payor basis or accepting a direct subsidy from the government to support a portion of the cost of the employer's program.

Paragraph 40 of the Financial Accounting Standards Board's (FASB) Statement of Financial Accounting Standard (SFAS) No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" requires that presently enacted changes in laws impacting employer-sponsored retiree health care programs which take effect in future periods be considered in current-period measurements for benefits expected to be provided in those future periods.Therefore, under FAS 106 guidance, measures of plan liabilities and annual expense on or after the date of enactment should reflect the effects of this Act. Pursuant to guidance from the FASB under FSP FAS 106-2, the retiree health obligations will reflect the estimated subsidy payments expected from the federal government for the participant groups anticipated to qualify for the subsidy. Participant groups who are not expected to qualify, or have not yet been determined whether they will qualify, for the federal subsidy will not impact the retiree health obligations. If any portion of this group is subsequently determined to qualify for the subsidy, the retiree health care obligations will be adjusted at the time of that determination. The Company has chosen to apply the guidance prospectively, impacting retiree health costs effective beginning with the quarter ended September 30, 2004. The Company adopted the provisions of FAS 106-2 on July 1, 2004. The impact is presented in Note F - Employee Benefits. Any decrease in expense that results from the Act will be deferred and will be credited to customers.

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 $5.1 billion and $5.2 billion at September 30, 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 104 sites with which it may be associated, including 58 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 $310 million and $309 million which is reflected in the Company's Condensed Consolidated Balance Sheets at September 30, 2004 and March 31, 2004, respectively. The potential high end of the range is presently estimated at approximately $541 million. The total net reserve has been increased by $1 million since March 31, 2004 primarily due to an additional $9 million accrual for anticipated remediation costs associated with a manufactured gas plant site. This additional accrual has been offset by approximately $8 million in spending.

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 (Multiple Intervenors) intervened in the cases and challenged the refund reports. Niagara Mohawk's reports determined that no refunds were due to the Multiple Intervenors, based on its position that, among other reasons, none of the customers actually took transmission service pursuant to the applicable FERC tariffs at issue and, instead, were taking bundled retail delivery service pursuant to state-approved tariffs. The Multiple Intervenors challenged Niagara Mohawk's filings, alleging that they did take service under the applicable tariffs and, as a result, were entitled to a partial refund of transmission charges dating back to 1998. On October 8, 2004, FERC issued an order finding that Niagara Mohawk's filings raised issues of material fact concerning whether the Multiple Intervenors took service under the applicable tariffs and are entitled to refunds and, if so, the magnitude of those refunds. FERC also directed that a settlement judge be appointed to aid the parties in settlement efforts. If the settlement efforts do not succeed, FERC will convene an evidentiary hearing to resolve the issues. The company can not predict the outcome of this proceeding.

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. On October 27, 2003, the court dismissed AMP's petition. AMP made a timely filing to appeal the court's decision but did not perfect 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 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 State 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 New York 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, and the Company's appeal from it, are discussed below under Retail Bypass. As of September 30, 2004, the NRG Affiliates owed the Company approximately $41 million for station service. In the event it is determined that the Company may not charge 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 9.

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, and oral argument was heard on July 12, 2004. 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, the Company had sued NRG and the NRG Affiliates in New York State Supreme Court (Onondaga County), seeking a declaratory ruling with respect to NRG's responsibilities for pollution control equipment and related fines and penalties under the agreement governing the sale of the Plants to the NRG Affiliates. NRG had filed a counterclaim and a motion for summary judgment on its counterclaim. The parties entered into a settlement agreement in October 2004, pursuant to which they agreed to withdraw their respective claims with prejudice.

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. 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 has filed for rehearing of these orders.

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 electricity-transmission, electricity-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 September 30, 2004
	Operating revenue		$ 66	$ 767	$ 79	$ 912
	Operating income before
		income taxes	29	128	-	157
	Depreciation and amortization		9	34	10	53
	Amortization of stranded costs		-	61	-	61
Three Months Ended September 30, 2003
	Operating revenue		$ 66	$ 791	$ 74	$ 931
	Operating income before
		income taxes	25	122	(5)	142
	Depreciation and amortization		8	33	9	50
	Amortization of stranded costs		-	44	-	44
Six Months Ended September 30, 2004
	Operating revenue		$ 128	$ 1,442	$ 233	$ 1,803
	Operating income before
		income taxes	54	214	25	293
	Depreciation and amortization		17	67	19	103
	Amortization of stranded costs		-	123	-	123
Six Months Ended September 30, 2003
	Operating revenue		$ 127	$ 1,491	$ 262	$ 1,880
	Operating income before
		income taxes	49	198	8	255
	Depreciation and amortization		17	65	18	100
	Amortization of stranded costs		-	87	-	87

(in millions of dollars)
		Electric -	Electric -
		Transmission	Distribution	Gas	Corporate	Total
September 30, 2004
	Goodwill	$ 303	$ 708	$ 215	$ -	$ 1,226
	Total assets	$ 1,535	$ 8,713	$ 1,756	$ 420	$ 12,424
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 (losses) on securities,
		net of taxes		(160)		(160)
September 30, 2004				$ 987	$ (1,557)	$ (570)

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

	For the Six Months Ended September 30,
	2004	2003
Unrealized gain/(losses) on securities	$ 107	$ (596)

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 six months ended September 30, 2004 and 2003 included the following components:

			Other Postretirement
($'s in 000's)	Pension Benefits		Benefits
For the Three Months Ended September 30,	2004	2003	2004	2003
Service cost	$ 6,927	$ 7,023	$ 2,482	$ 2,157
Interest cost	17,906	18,716	15,276	14,488
Expected return on plans' assets	(17,033)	(17,848)	(11,195)	(8,644)
Amortization of prior service cost	290	290	(68)	-
Recognized actuarial loss	7,066	4,507	6,360	5,749
Net periodic benefit cost	$ 15,156	$ 12,688	$ 12,855	$ 13,750
Settlement loss	$ 185	$ -	$ -	$ -
			Other Postretirement
($'s in 000's)	Pension Benefits		Benefits
For the Six Months Ended September 30,	2004	2003	2004	2003
Service cost	$ 14,471	$ 14,046	$ 5,027	$ 4,314
Interest cost	35,285	37,432	30,051	28,976
Expected return on plans' assets	(33,935)	(35,695)	(23,123)	(17,289)
Amortization of prior service cost	580	580	(133)	-
Recognized actuarial loss	13,233	9,013	12,901	11,498
Net periodic benefit cost	$ 29,634	$ 25,376	$ 24,723	$ 27,499
Settlement loss	$ 185	$ -	$ -	$ -

In May 2004, the Financial Accounting Standards Board issued Staff Position 106-2, providing final guidance on "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003". The Company adopted the provisions of FAS 106-2 during the three months ended September 30, 2004. The Company recorded the effects of the subsidy in measuring its net periodic postretirement benefit cost for the three months ended September 30, 2004. Effective July 1, 2004, this resulted in a reduction in the Company's accumulated postretirement benefit obligation (APBO) for the subsidy related to benefits attributed to past service of $71 million.

The subsidy resulted in a reduction in the Company's current periodic postretirement benefit costs for the three months ended September 30, 2004. Any decrease in expense that results from the Act will be deferred and will be credited to customers.

($'s in 000's)
Reduction in Net Periodic Benefit Cost For the Three Months Ended September 30,	2004
Service cost	$ 30
Interest cost	1,072
Recognized actuarial loss	1,734
Total expense reduction	$ 2,836
Annualized expense reduction	$ 11,343

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 September 30, 2004 increased by approximately $8 million from the comparable period in the prior year. The increase is primarily due to lower interest costs of approximately $10 million, decreased pension expense of $14 million, and reduced bad debt expense of $5 million, offset by an increase in income taxes of $13 million, an increase in depreciation expense of $3 million, and a decrease in electric margin of $4 million.

Net income for the six months ended September 30, 2004 increased by approximately $45 million from the comparable period in the prior year. The increase is primarily due to lower interest costs of approximately $29 million, increased electric margin of $5 million (net of amortization of stranded costs and gross receipts tax), decreased pension expense of $14 million, and reduced bad debt expense of $18 million, offset by an increase in income taxes of $24 million.


REVENUES

Electric revenues decreased approximately $23 million and $48 million for the three and six months ended September 30, 2004, respectively, as compared to the comparable periods in the prior year. The table below details components of this fluctuation.

Period ended September 30, 2004
(In millions of dollars)
			Three Months	Six Months
	Retail sales		$ (22)	$ (45)
	Sales for resale		(1)	(3)
		Total	$ (23)	$ (48)

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 $5 million and decreased by $29 million in the three and six months ended September 30, 2004, respectively, as compared to the comparable periods in the prior year. The increase for the three months ended September 30, 2004 is primarily a result of higher gas prices passed through to customers. The decrease for the six months ended September 30, 2004 can be attributed to both decreased gas prices and decreased volumes of gas purchased. The table below details components of this fluctuation.

Period ended September 30, 2004
(In millions of dollars)
			Three Months	Six Months
	Cost of purchased gas		$ 5	$ (28)
	Delivery revenue		-	1
	Other		-	(2)
		Total	$ 5	$ (29)

The volume of gas sold for the three months ended September 30, 2004, excluding transportation of customer-owned gas decreased 0.124 million Dekatherms (Dth) or a 3.4 percent decrease from the comparable period in the prior year.

The volume of gas sold for the six months ended September 30, 2004, excluding transportation of customer-owned gas decreased 1.767 million Dth or a 10.4 percent decrease from the comparable period in the prior year. The decrease is a result of lower overall demand as a result of milder weather.

OPERATING EXPENSES

Purchased electricity decreased approximately $33 million and $83 million for the three and six months ended September 30, 2004, respectively, as compared to the comparable periods in the prior year. The volume of kWh sold for the three and six months ended September 30, 2004 decreased 112 million kWh (1%) and 1.4 billion kWh (9%), respectively, as compared to the comparable periods in the prior year. This volume decrease was compounded by a 6% decrease and 1.5% decrease in the price of electricity for the three and six months ended September 30, 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 $5 million and decreased approximately $28 million for the three and six months ended September 30, 2004, respectively, as compared to the comparable periods in the prior year. Contributing to the increase of $5 million in the three months ended September 30, 2004 was an increase in gas costs of $6 million which was offset by a decrease in volumes purchased of $1 million. Contributing to the decrease of $28 million for the six months ended September 30, 2004 was a $16 million decrease in gas prices and a $12 million decrease in volumes purchased. 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 $23 million and $34 million for the three and six months ended September 30, 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	Six Months
Decreased bad debt expense	$ (5)	(18)
Pension settlement loss	(14)	(14)
Loss on the sale of asset	-	4
April 2003 ice storm	-	(6)
Other	(4)	-
Total	$ (23)	(34)

The reduction in bad debt expense was mainly the result of a decrease in accounts receivable and improved collection practices. The pension settlement loss deferral of $14 million reflects the July 2004 approval by the PSC 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 that it recorded to expense in the third and fourth quarters of fiscal 2004. 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 a building in the previous fiscal quarter. This sale resulted in a charge of approximately $4 million (pre-tax) to expense to reflect its share of its unrecovered cost of this facility, in accordance with the PSC's order on this matter. Other expense for the three and six months ended September 30, 2004 as compared to the same period in the prior year, reflects increased distribution electric and gas operation and maintenance costs offset by ongoing reduced costs from merger-related efficiencies.

Amortization of stranded costs increased approximately $18 million and $36 million for the three and six months ended September 30, 2004, respectively, as compared to the comparable periods in the prior year in accordance with the Merger Rate Plan. Under the Merger Rate Plan, which began on January 1, 2002, the stranded investment balance per the Merger Rate plan is being amortized unevenly at levels that increase during the term of the ten-year plan that ends December 31, 2011. The increases in the amortization of stranded costs is included in the Company rate plan and does not impact net income.

Other taxes decreased approximately $3 million and $8 million for the three and six months ended September 30, 2004, respectively, as compared to the comparable periods in the prior year. This decrease is primarily due to a reduction in gross receipts tax (GRT) due to lower rates and reduced revenues. Payroll taxes also decreased as a result of fewer employees due to the significant number of retirements that have occurred in fiscal 2004.

Income taxes increased approximately $13 million and $24 million for the three and six months ended September 30, 2004, respectively, as compared to the comparable periods in the prior year primarily due to higher book taxable income. Also, in the six months ended September 30, 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 $29 million for the three and six months ended September 30, 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. Also, 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) 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 September 30, 2004, the Company's principal sources of liquidity included cash and cash equivalents of $16 million and accounts receivable of $518 million. The Company has a negative working capital balance of $555 million primarily due to short-term debt to affiliates of $467 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 $335 million for the six months ended September 30, 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 six months ended September 30, 2003 when the payables came due.
• Increased net income (see earnings discussion above) of approximately $45 million.
• Increased stranded cost revenues for the return of previously incurred stranded costs of approximately $36 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 is not included in net income.
• Increased provision for deferred income taxes of approximately $27 million. This was mainly attributable to utilization of net operating loss carryforwards. For the six months ended September 30, 2003, there was no net operating loss carryforward utilization.
• $149 million increase due to a decline in required funding of employee pension and other benefits.

Net cash used in investing activities decreased by approximately $72 million for the six months ended September 30, 2004 from the comparable period in the prior year. The decrease was primarily due to a reduction in restricted cash of $43 million, mainly attributable to funds being released from deposits. In addition, a decrease in construction additions of $33 million was primarily due 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.

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 $408 million of cash was used in financing activities for the six months ended September 30, 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 2003, the Company received a $309 million contribution from its parent company and increased its short-term debt to affiliates by $471 million. There were no similar receipts in the current period. The change in receipts is offset by a decrease in reductions in long-term debt of approximately $1 billion.

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.

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

Pension settlement loss. In February 2004, the Company reached an agreement with PSC Staff that would provide rate recovery for approximately $14 million of the $30 million pension settlement loss incurred in fiscal 2003. This agreement was approved by the full New York State Public Service Commission in July 2004. In addition, the agreement covers the funding of the entire settlement loss to benefit plan trust funds. The Company funded the non-recoverable portion of this loss in the quarter ended September 30, 2004. The company recorded a $14 million decrease in pension expense for the recoverable portion of the loss during the quarter ended September 30, 2004. In addition, the Company has recently filed a petition with the PSC seeking recovery of its fiscal year 2004 settlement losses and is unable to predict the outcome of this filing. For further discussion of the settlement losses see the Company's Annual Report on Form 10-K for the period ended March 31, 2004, Part II , Item 8. Financial Statements and Supplementary Data - Note H Employee Benefits.

Elevated equipment voltage. The PSC issued an order in July 2004 seeking comments on a proposal which, if adopted, would require all electric utilities in the state to test annually all of their publicly accessible transmission and distribution facilities for elevated equipment voltage.  The proposal also contemplates strict compliance requirements and potential financial penalties for failure to achieve testing and inspection targets.  It is not yet clear how broad in scope the inspection requirements would be, nor is it clear how the financial penalty mechanism being contemplated would be administered, if adopted. The Company and other utilities filed comments on this proposal in early October.

Renewable Portfolio Standard. On February 19, 2003, the PSC commenced a proceeding to create a renewable portfolio standard for New York State, establishing a working target that 25% of the energy retailed in New York would be generated from qualifying renewable resources. An administrative law judge issued a recommended decision on June 3, 2004 for review by the full Commission. On September 24, 2004, the PSC issued an order in response to the recommended decision setting forth a program for meeting the statewide renewable targets. Under the program contemplated in the order, the New York State Energy Research and Development Authority (NYSERDA), a state agency that administers certain state-sponsored energy efficiency programs, will serve as a central procurement administrator and contracting entity. Utilities would not be required to enter into any contracts with suppliers. Instead, NYSERDA would conduct bidding processes, through which the winning renewable energy projects would be awarded contracts with NYSERDA. Under the contracts, NYSERDA would make payments to the projects for the above market costs to finance the projects. Funding for the contract payments would be derived from a volumetric surcharge assessed by investor-owned utilities on customer electric delivery bills (RPS Surcharge), which would be set annually by the PSC. The investor-owned utilities would collect the RPS Surcharge and pass along the funds to NYSERDA in a manner much like what is currently done for the other energy efficiency programs being annually administered by NYSERDA and funded through a volumetric "systems benefit charge". The proceeding has been continued by the PSC to develop further implementation details, with the intention of commencing the program by 2006.

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 September 30, 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 six months ended September 30, 2004, were approximately 1.57% and 1.45%, respectively.

There were no material changes in the Company's market risk or market risk strategies during the three months ended September 30, 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 September 30, 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

Alliance for Municipal Power v. New York State Public Service Commission: As described in the Company's 10-K for the fiscal year ended March 31, 2004, the Alliance for Municipal Power (AMP) had 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. On October 27, 2003, the court dismissed AMP's petition. AMP made a timely filing to appeal the court's decision but did not perfect its appeal.

Niagara Mohawk Power Corporation v. NRG Energy, Inc., Huntley Power L.L.C. and Dunkirk Power L.L.C. As described in the Company's 10-K for the fiscal year ended March 31, 2004, with respect to the claims asserted in the Clean Air Act lawsuit that is also discussed in the 10-K, the Company had sued NRG and certain affiliates in New York State Supreme Court, seeking a declaratory ruling with respect to NRG's responsibilities for pollution control equipment and related fines and penalties, and NRG had filed a counterclaim and a motion for partial summary judgment on its counterclaim. The parties entered into a settlement agreement in October 2004, pursuant to which they agreed to withdraw their respective claims with prejudice.

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 September 30, 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 September 30, 2004 to be signed on its behalf by the undersigned thereunto duly authorized.

	NIAGARA MOHAWK POWER CORPORATION
Date: November 12, 2004	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