Niagara Mohawk Power (NMKBP) 10-Q 2006 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2005

OR

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

For the transition period from                    to                    

Commission	Registrant, State of Incorporation	I.R.S. Employer
File Number	Address and Telephone Number	Identification No.
1-2987	Niagara Mohawk Power Corporation	15-0265555
	(a New York corporation)
	300 Erie Boulevard West
	Syracuse, New York 13202
	315.474.1511

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.

YESþ               NOo

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

YESo               NOþ

The number of shares outstanding of each of the issuer’s classes of common stock, as of August 10, 2005, were as follows:

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

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q — For the Quarter Ended June 30, 2005

	PAGE
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Consolidated Statements of Operations and Comprehensive Income		3
Condensed Consolidated Statements of Retained Earnings		4
Condensed Consolidated Balance Sheets		5
Condensed Consolidated Statements of Cash Flows		7
Notes to Unaudited Condensed Consolidated Financial Statements		8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 3. Quantitative and Qualitative Disclosures About Market Risk		18
Item 4. Controls and Procedures		19
PART II — OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders		19
Item 5. Other Information		19
Item 6. Exhibits		19
Signature		20
Exhibit Index		21

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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
	June 30,
	2005			2004
Operating revenues:
Electric	$	770,830		$	735,934
Gas		188,002			154,305
Total operating revenues		958,832			890,239
Operating expenses:
Purchased electricity		333,803			333,705
Purchased gas		117,423			83,239
Other operation and maintenance		170,373			172,050
Depreciation and amortization		50,389			50,686
Amortization of stranded costs		67,140			61,453
Other taxes		53,189			53,378
Income taxes		47,130			31,114
Total operating expenses		839,447			785,625
Operating income		119,385			104,614
Other income (deductions), net		(1,570	)		2,748
Operating and other income		117,815			107,362
Interest:
Interest on long-term debt		40,396			48,336
Interest on debt to associated companies		16,440			15,078
Other interest		3,630			3,113
Total interest expense		60,466			66,527
Net income		57,349			40,835
Dividends on preferred stock		407			841
Income available to common shareholder	$	56,942		$	39,994

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

	Three Months Ended
	June 30,
	2005			2004
Net income	$	57,349		$	40,835
Other comprehensive income (loss):
Unrealized losses on securities, net of tax		(1,311	)		(55	)
Hedging activity, net of tax		411			—
Change in additional minimum pension liability, net of tax		508			—
Total other comprehensive (loss)		(392	)		(55	)
Comprehensive income	$	56,957		$	40,780

     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

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NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Condensed Consolidated Statements of Retained Earnings
(In thousands of dollars)
(UNAUDITED)

	Three Months Ended
	June 30,
	2005			2004
Retained earnings at beginning of period	$	473,287		$	220,966
Net income		57,349			40,835
Dividends on preferred stock		(407	)		(841	)
Retained earnings at end of period	$	530,229		$	260,960

The accompanying notes are an integral part of these financial statements

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NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Condensed Consolidated Balance Sheets
(In thousands of dollars)
(UNAUDITED)

	June 30,		March 31,
	2005		2005
ASSETS
Utility plant, at original cost:
Electric plant	$	5,399,367	$	5,347,832
Gas plant		1,520,273		1,517,804
Common plant		321,257		330,437
Construction work-in-progress		77,998		69,702
Total utility plant		7,318,895		7,265,775
Less: Accumulated depreciation and amortization		2,144,760		2,108,379
Net utility plant		5,174,135		5,157,396
Goodwill		1,224,025		1,224,025
Pension intangible		40,339		40,339
Other property and investments		55,427		55,048
Current assets:
Cash and cash equivalents		17,285		19,922
Restricted cash		21,224		7,367
Accounts receivable (less reserves of $127,538 and $126,085, respectively, and includes receivables from associated companies of $12,805 and $6,654, respectively)		463,183		571,552
Materials and supplies, at average cost:
Gas storage		51,040		3,498
Other		14,936		17,739
Derivative instruments		17,381		35,326
Prepaid taxes		—		44,273
Current deferred income taxes		228,942		307,431
Regulatory asset — swap contracts		187,600		203,558
Other		10,083		9,772
Total current assets		1,011,674		1,220,438
Regulatory and other non-current assets:
Regulatory assets (Note B):
Stranded costs		2,698,252		2,765,392
Swap contracts		456,500		415,394
Regulatory tax asset		79,780		79,933
Deferred environmental restoration costs (Note C)		422,035		431,000
Pension and postretirement benefit plans		519,156		501,358
Additional minimum pension liability		194,118		194,302
Loss on reacquired debt		65,244		67,162
Other		384,000		330,094
Total regulatory assets		4,819,085		4,784,635
Other non-current assets		32,280		36,481
Total regulatory and other non-current assets		4,851,365		4,821,116
Total assets	$	12,356,965	$	12,518,362

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

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NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Condensed Consolidated Balance Sheets

(In thousands of dollars)

(UNAUDITED)

	June 30,		March 31,
	2005		2005
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 (Note E)		12,569		12,961
Retained earnings		530,229		473,287
Total common stockholder’s equity		3,659,664		3,603,114
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
Long-term debt		1,448,686		1,723,569
Long-term debt to affiliates		1,200,000		1,200,000
Total capitalization		6,349,520		6,567,853
Current liabilities:
Accounts payable (including payables to associated companies of $22,221 and $36,440, respectively)		250,459		271,275
Customers’ deposits		26,351		26,900
Accrued interest		46,048		82,945
Accrued taxes		7,501		—
Short-term debt to affiliates		303,549		400,500
Current portion of swap contracts		187,600		203,558
Current portion of long-term debt		825,420		550,420
Other		77,427		107,871
Total current liabilities		1,724,355		1,643,469
Other non-current liabilities:
Accumulated deferred income taxes		1,652,584		1,711,630
Liability for swap contracts		456,500		415,394
Employee pension and other benefits		470,879		434,855
Additional minimum pension liability		236,199		236,198
Liability for environmental remediation costs (Note C)		422,035		431,000
Nuclear fuel disposal costs		146,578		145,562
Cost of removal regulatory liability		323,747		318,455
Other		574,568		613,946
Total other non-current liabilities		4,283,090		4,307,040
Commitments and contingencies (Notes B and C)		—		—
Total capitalization and liabilities	$	12,356,965	$	12,518,362

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

6

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Condensed Consolidated Statements of Cash Flows
(In thousands of dollars)
(UNAUDITED)

	Three Months ended
	June 30,
	2005			2004
Operating activities:
Net income	$	57,349		$	40,835
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		50,389			50,686
Amortization of stranded costs		67,140			61,453
Provision for deferred income taxes		22,541			26,217
Pension and other benefit plans expense		28,437			17,735
Cash paid to pension and postretirement benefit plan trusts		(23,500	)		(34,057	)
Changes in operating assets and liabilities:
Decrease in accounts receivable, net		75,869			70,581
Increase in materials and supplies		(44,739	)		(38,804	)
Decrease in prepaid taxes		44,273			42,125
Decrease in accounts payable and accrued expenses		(51,808	)		(15,919	)
Decrease in accrued interest and taxes		(29,396	)		(42,388	)
Other, net		(25,698	)		35,047
Net cash provided by operating activities		170,857			213,511
Investing activities:
Construction additions		(57,101	)		(51,726	)
Change in restricted cash		(13,857	)		(3,249	)
Other investments		(460	)		99
Other		(4,718	)		1,406
Net cash used in investing activities		(76,136	)		(53,470	)
Financing activities:
Dividends paid on preferred stock		(407	)		(841	)
Reductions in long-term debt		—			(232,402	)
Net change in short-term debt to affiliates		(96,951	)		82,000
Net cash used in financing activities		(97,358	)		(151,243	)
Net (decrease) increase in cash and cash equivalents		(2,637	)		8,798
Cash and cash equivalents, beginning of period		19,922			26,840
Cash and cash equivalents, end of period	$	17,285		$	35,638
Supplemental disclosures of cash flow information:
Interest paid	$	96,084		$	109,121
Income taxes paid	$	8,000		$	—

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

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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 results of operations for the interim periods presented. The March 31, 2005 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, 2005. As such, the March 31, 2005 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, 2005.

The Company’s electric sales tend to be substantially higher in summer and winter months as related to weather patterns in its service territory; whereas, 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 period ended June 30, 2005 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 plc (formerly know as National Grid Transco plc).

New Accounting Standards:In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 123R, “Share-Based Payment.” SFAS No. 123R addresses the accounting for transactions in which a company receives employee services in exchange for (a) equity instruments of the company or (b) liabilities that are based on the fair value of the company’s equity instruments or that may be settled by the issuance of such equity instruments. SFAS No. 123R also eliminates the ability to account for share-based compensation transactions using Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and requires that such transactions be accounted for using a fair-value-based method. SFAS No. 123R was originally effective for public companies for interim or annual periods beginning after June 15, 2005. In April 2005, the SEC delayed the effective date of SFAS No. 123R to annual, rather than interim, periods that begin after June 15, 2005. The SEC’s new rule results in a six-month deferral for the Company. The Company does not anticipate that adoption of SFAS No. 123R will have a material impact on its results of operations or its financial position.

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). FIN 47 will result in (a) more consistent recognition of liabilities relating to asset retirement obligations, (b) more information about expected future cash outflows associated with those obligations and (c) more information about investments in long-lived assets because additional asset retirement costs will be recognized as part of the carrying amounts of the assets.

8

FIN 47 clarifies that the term conditional asset retirement obligation as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations”, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional upon a future event that may or may not be within the entity’s control. The obligation to perform the asset retirement activity is unconditional even though the uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

This statement will be effective for the fiscal year ended March 31, 2006 for the Company. The adoption of FIN 47 is not expected to have a material impact on the Company’s results of operations or its financial position.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.” Previously, APB No. 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements” required the inclusion of the cumulative effect of changes in accounting principle in net income of the period of the change. SFAS No. 154 requires companies to recognize a change in accounting principle, including a change required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. The Company does not anticipate that adoption of SFAS No. 154 will have a material impact on its results of operations or its financial position.

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” (SFAS 71) permits a public utility, regulated on a cost-of-service basis, to defer certain costs, which would otherwise be charged to expense, when authorized to do so by the regulator. These deferred costs are known as regulatory assets, which in the case of the Company are approximately $5.0 billion as of June 30, 2005 and March 31, 2005. 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 SFAS 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.

9

In the event the Company determines, as a result of lower than expected revenues and/or higher than expected costs, that its net regulatory assets are not probable of recovery, it can no longer apply the principles of SFAS 71 and would be required to record an after-tax, non-cash charge against income for any remaining unamortized regulatory assets and liabilities. If the Company could no longer apply SFAS 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.

Under the Merger Rate Plan, the Company resets its competitive transition charge (CTC) every two years. On July 29, 2005, the Company filed for its CTC to be reset in prices beginning January 1, 2006. The CTC reset is intended to account for changes in forecast of electricity and natural gas commodity prices, and the effects those changes have on the Company’s above market payments under legacy power contracts that would otherwise be stranded. The Company is also authorized to recover amounts exceeding $100 million in the deferral accounts (projected through the end of the two-year CTC reset period). The Company included a proposal to recover the excess balance of deferral accounts as of June 30, 2005 of $196 million and a projection of other deferral amounts through the end of the two-year period, although, the Company’s deferral recovery is subject to regulatory review and approval of the Public Service Commission (PSC).

NOTE C — COMMITMENTS AND CONTINGENCIES

Environmental Contingencies:The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations. Like most other industrial companies, the Company’s transmission and distribution companies use or generate some hazardous and potentially hazardous wastes and by-products. Under federal and state Superfund laws, potential liability for the historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.

The Environmental Protection Agency (EPA), Department of Environmental Conservation (DEC), as well as private entities have alleged that Niagara Mohawk is a potentially responsible party under state or federal law for the remediation of an aggregate of approximately 100 sites, including 54 which are Company owned. The Company’s most significant liabilities relate to former manufactured gas plant (MGP) facilities formerly owned or operated by the Company’s predecessors. The Company is currently investigating and remediating, as necessary, those MGP sites and certain other properties under agreements with the EPA and DEC.

The Company believes that obligations imposed on the Company as a result of the environmental laws are not likely to have a material adverse impact on its financial condition, results of operations or cash flows. 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.

10

The Company is pursuing claims against potentially responsible parties to recover investigation and remediation costs, but the Company cannot predict the success of such claims. As of June 30, 2005 and March 31, 2005, the Company has accrued a liability in the amount of $422 million and $431 million, respectively, which is reflected in the Company’s Consolidated Balance Sheets. The decrease in the accrual is primarily due to actual spending at the sites for which the expense has previously been recognized. The potential high end of the range at June 30, 2005 is presently estimated at approximately $549 million.

Legal Matters:

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 a 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. A state collection action and other proceedings have all been stayed pending the outcome of the FERC proceeding. As of June 30, 2005, the NRG Affiliates owed Niagara Mohawk approximately $45.0 million for station service. On November 19, 2004 and April 22, 2005, the FERC issued orders 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 appealed the orders to the US Court of Appeals for the District of Columbia Circuit. The Court has consolidated this appeal with the two retail bypass cases discussed below. Although subject to regulatory review and approval by the PSC, the Company believes that if the Court were to uphold the FERC’s orders, the Company will be permitted to recover, under its rate plans, the station service charges not paid by the NRG Affiliates.

New York ISO Mitigation Error:On March 4, 2005, FERC issued an order on remand from the U.S. Court of Appeals for the District of Columbia Circuit (PSEG Energy Resource & Trade LLC v. New York Independent System Operator,FERC Docket No. EL02-16; H.Q. Energy
Services, Inc. v. New York Independent System Operator,FERC Docket No. EL01-19). In this case, the New York Independent System Operator (NYISO) had “mitigated”, or retroactively reduced, bid prices of approximately $3,500 per megawatt-hour to about $300 per megawatt-hour during a period of several hours on May 8 and 9, 2000. FERC had approved the NYISO’s action, but the Court of Appeals reversed FERC. On remand, FERC reinstated the original higher market prices. The Company received and paid an invoice from the NYISO in July 2005. Since then, the generators have filed a new complaint with FERC stating that the NYISO did not execute the FERC’s March 4 order properly, and the NYISO has responded that it did execute the order properly. As reported in the Company’s Annual Report on Form 10-K for fiscal year ended March 31, 2005, the Company still estimates a potential loss ranging from $7 million to $10 million, with interest.

Retail Bypass:As discussed in more detail in the Company’s Form 10-K for the fiscal year ended March 31, 2005, a number of generators have complained or withheld payments associated with the Company’s delivery of station service to their generation facilities, arguing

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that they should be permitted to bypass the Company’s retail charges. The FERC issued two orders on complaints filed by Niagara Mohawk’s station service customers 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 Niagara Mohawk’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 Niagara Mohawk’s state-jurisdictional station service charges for electricity, including those set forth in the filing that was approved by the Public Service Commission (PSC) on November 25, 2003. Niagara Mohawk filed for rehearing of these orders, and the FERC denied these requests in January 2005. Niagara Mohawk has appealed 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.

The Court of Appeals has consolidated these appeals for hearing, and briefing is scheduled to be completed in January 2006.

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. The Company has requested recovery of lost revenues resulting from FERC’s station service rulings as part of its deferral recovery proposal made with the PSC July 29, 2005. The Company’s deferral recovery is subject to regulatory review and approval of the PSC.

NOTE D — SEGMENT INFORMATION

The Company’s reportable segments are electricity-transmission, electricity-distribution, including the sub-segment stranded cost recoveries and gas-distribution. 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.

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					Electricity –		Total
	Electricity –		Electricity –		Stranded Cost		Electricity		Gas –
(in 000’s)	Transmission		Distribution		Recoveries		Distribution		Distribution		Corporate		Total
Three Months Ended June 30, 2005
Operating revenues	$	63	$	584	$	124	$	708	$	188	$	—	$	959
Operating income before income taxes		26		89		29		118		23		—		167
Depreciation and amortization		9		31		—		31		10		—		50
Amortization of stranded costs		—		—		67		67		—		—		67
Three Months Ended June 30, 2004
Operating revenues	$	62	$	583	$	91	$	674	$	154	$	—	$	890
Operating income before income taxes		25		64		22		86		25		—		136
Depreciation and amortization		8		34		—		34		9		—		51
Amortization of stranded costs		—		—		61		61		—		—		61

					Electricity –		Total
	Electricity –		Electricity –		Stranded Cost		Electricity		Gas –
(in 000’s)	Transmission		Distribution		Recoveries		Distribution		Distribution		Corporate		Total
June 30, 2005
Goodwill	$	303	$	706	$	—	$	706	$	215	$	—	$	1,224
Total assets		1,566	$	5,135		3,360		8,495		1,856		440		12,357
March 31, 2005
Goodwill	$	303	$	706	$	—	$	706	$	215	$	—	$	1,224
Total assets		1,557	$	5,193		3,402		8,595		1,819		547		12,518

NOTE E — ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

	Unrealized			Additional					Total
	Gains and			Minimum					Accumulated
	Losses on			Pension					Other
	Available-for-			Liability			Cash Flow		Comprehensive
(in 000’s)	Sale Securities			Adjustment			Hedges		Income (Loss)
March 31, 2005	$	1,706		$	(1,557	)	$	12,812	$	12,961
Unrealized losses on securities, net of tax		(1,311	)							(1,311	)
Hedging activity, net of tax								411		411
Change in additional minimum pension liability, net of tax					508					508
June 30, 2005	$	395		$	(1,049	)	$	13,223	$	12,569

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

	For the Three Months
	Ended June 30,
(in 000’s)	2005			2004
Unrealized gain on securities	$	874		$	37
Hedging activities		(274	)		6,720
Change in additional minimum pension liability		(339	)		—
	$	261		$	6,757

NOTE F — EMPLOYEE BENEFITS

As discussed in the Company’s Annual Report on Form 10-K for the year ended March 31, 2005, the Company provides benefits to retirees in the form of pension and other postretirement benefits. The qualified defined benefit pension plan cover substantially all employees meeting certain minimum age and service requirements. Funding for the qualified defined benefit pension plan 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 plan’s 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 former 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, 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 months ended June 30, 2005 and 2004 included the following components:

							Other Postretirement
($’s in 000’s)	Pension Benefits						Benefits
For the Three Months Ended June 30,	2005			2004			2005			2004
Service cost	$	7,658		$	7,545		$	4,445		$	2,545
Interest cost		18,188			17,398			17,375			14,775
Expected return on plan’s assets		(16,089	)		(16,903	)		(11,384	)		(11,928	)
Amortization of prior service cost		826			290			3,647			(65	)
Recognized actuarial loss		8,471			6,154			7,813			6,541
Net periodic benefit cost	$	19,054		$	14,484		$	21,896		$	11,868

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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, the following:

(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, 2005, 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 June 30, 2005 was not significantly different from the comparable period in the prior year for normal operations. The increase of $17 million in net income is primarily due to a positive adjustment to electric revenues of $32 million due to a one-

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time recognition of a regulatory asset related to the recovery of a previously fully reserved accounts receivable and lower interest costs of approximately $6 million. These increases in net income were offset by increased income tax expense of approximately $16 million.

REVENUES

Electric revenuesincreased approximately $35 million for the three months ended June 30, 2005 from the comparable period in the prior year. The increase in revenue is primarily due to a one-time recognition of a $32 million regulatory asset related to the recovery of a previously fully reserved accounts receivable balance. Although sales of electricity were not significantly different from the comparable period in the prior year for normal operations, kWh deliveries decreased. This decrease was offset by increases in the price of electricity that were passed on to customers.

Gas revenuesincreased approximately $34 million for the three months ended June 30, 2005 from the comparable period in the prior year. This increase is primarily due to increased purchased gas prices being passed on to customers and an increase in the volume of gas sold both on system to the Company’s customers and off-system for resale in interstate commerce. The volume of gas sold for the three months ended June 30, 2005 increased 0.5 million Dekatherms (Dth) or a 4.1 percent increase from the comparable period in the prior year due to milder weather in the prior year.

OPERATING EXPENSES

Purchased electricityremained consistent with the prior year. Although kWhs purchased to supply retail sales customers decreased from the prior year, purchased electricity expense remained consistent with the prior year due to the increased cost of electricity. These costs do not impact electric margin or net income as the Company’s rate plans allow full recovery of these costs from customers. The decrease in kWh was due to customers that have been migrating to competitive suppliers for their commodity requirements.

Purchased gasexpense increased $34 million for the three months ended June 30, 2005 as compared to the same period in the prior year primarily as a result of a $18 million increase in gas prices, an increase of $4 million in the volume of gas purchased for system customers and an increase of $12 million related to gas purchased for off-system sales. These costs do not impact gas margin or net income as the Company’s rate plans allow full recovery of these costs from customers.

Other operation and maintenance expensedecreased approximately $2 million for the three months ended June 30, 2005 from the comparable period in the prior year. The table below details components of this fluctuation.

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Three months ended
June 30, 2005
(In millions of dollars)
Prior year loss on the sale of facility	$	(4	)
Increase storm costs		4
Other		(2	)
Total	$	(2	)

In the comparable period in the prior year, the Company completed the sale of a building resulting in a charge of approximately $4 million to expense to reflect its share of unrecovered costs of the facility. The Company did not record a similar loss in the current quarter. This was offset by increased costs associated with numerous small storms and outages. These items were recorded to expense in the three months ended June 30, 2005 without a comparable charge in the prior year. The decrease of $2 million in other expenses for the three months ended June 30, 2005, reflects ongoing savings from merger related efficiencies.

Amortization of stranded costsincreased approximately $6 million for the three months ended June 30, 2005 from the comparable period in the prior year in accordance with the Merger Rate Plan. Since January 31, 2002, the stranded investment balance per the Merger Rate plan is being amortized unevenly at levels that increase in later years during the term of the ten-year plan that ends December 31, 2011. The increase in the amortization of stranded costs is included in the Company’s rate plan and does not impact net income.

Income taxesincreased approximately $16 million for the three months from the comparable period in the prior year. This increase is primarily due to higher book income.

NON-OPERATING EXPENSES

Interest chargesdecreased $6 million for the three months ended June 30, 2005 from the comparable period in the prior year. This decrease is primarily due to the redemption of $530 million of long-term debt during the previous fiscal year.

LIQUIDITY AND CAPITAL RESOURCES

(See the Company’s Annual Report on Form 10-K for the period ended March 31, 2005, 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 June 30, 2005, the Company’s principal sources of liquidity included cash and cash equivalents of $17 million and accounts receivable of $463 million. The Company has a negative working capital balance of $713 million primarily due to debt payments due within one year of $825 million and short-term debt to affiliates of $304 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 and to cover debt requirements.

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Net cash provided by operating activitiesdecreased approximately $43 million for the three months ended June 30, 2005 from the comparable period in the prior year. The primary reasons for the decrease in operating cash flow are increased accounts payable payments.

Net cash used in investing activitiesincreased by approximately $23 million for the three months ended June 30, 2005 from the comparable period in the prior year. This increase was primarily due to increases in capital expenditures and increased restricted cash through required deposits related to commodity hedges.

Net cash used in financing activitiesdecreased $54 million for the three months ended June 30, 2005 from the comparable period in the prior year. This decrease is primarily due to the payment of $232 million of long-term debt offset by borrowings of short-term debt of $82 million in the prior year. In the current year, the Company repaid $97 million of short-term borrowings.

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, 2005, 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

Under the Merger Rate Plan, the Company resets its competitive transition charge (CTC) every two years. On July 29, 2005, the Company filed for its CTC to be reset in prices beginning January 1, 2006. The CTC reset is intended to account for changes in forecast of electricity and natural gas commodity prices, and the effects those changes have on the Company’s above market payments under legacy power contracts that would otherwise be stranded. The Company is also authorized to recover amounts exceeding $100 million in the deferral accounts (projected through the end of the two-year CTC reset period). The Company included a proposal to recover the excess balance of deferral accounts as of June 30, 2005 of $196 million and a projection of other deferral amounts through the end of the two-year period, although, the Company’s deferral recovery is subject to regulatory review and approval of the Public Service Commission (PSC).

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There were no material changes in the Company’s market risk or market risk strategies during the three months ended June 30, 2005. For a detailed discussion of market risk, see the Company’s Annual Report on Form 10-K for fiscal year ended March 31, 2005, Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

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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. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives. 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.

During the most recent fiscal quarter, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

As reported in the Company’s for 10-K for the fiscal year ended March 31, 2005, on May 5, 2005, by unanimous written consent of the sole common stockholder, the following actions were taken:

• The following persons were elected as directors: William F. Edwards, Michael E. Jesanis, Clement E. Nadeau, Kwong O. Nuey, Jr. and Anthony C. Pini.

• PricewaterhouseCoopers LLP, an independent registered public accounting firm, was appointed the Company’s auditor for the fiscal year ending March 31, 2006.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

The exhibit index is incorporated herein by reference.

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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 June 30, 2005 to be signed on its behalf by the undersigned thereunto duly authorized.

	NIAGARA MOHAWK POWER CORPORATION
Date: August 12, 2005	By	/s/ Marcy L. Reed
		Marcy L. Reed
		Authorized Officer and Controller and Principal Accounting Officer

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EXHIBIT INDEX

Exhibit
Number	Description
31.1	Certification of Principal Executive Officer
31.2	Certification of Principal Financial Officer
32	Certifications Pursuant to 18 U.S.C.1350

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