Niagara Mohawk Power (NMKBP) 10-Q 2006 Q2 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 September 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 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)	15-0265555
	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.

YES  þ                     NO  o

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

YES  o                     NO  þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YES  o                     NO  þ

The number of shares outstanding of each of the issuer’s classes of common stock, as of November 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 September 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		16
Item 3. Quantitative and Qualitative Disclosures About Market Risk		22
Item 4. Controls and Procedures		22
PART II — OTHER INFORMATION
Item 6. Exhibits		22
Signature		23
Exhibit Index		24

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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					Six Months Ended
	September 30,					September 30,
	2005		2004			2005			2004
Operating revenues:
Electric	$	887,025	$	833,698		$	1,657,855		$	1,569,632
Gas		94,056		79,170			282,058			233,475
Total operating revenues		981,081		912,868			1,939,913			1,803,107
Operating expenses:
Purchased electricity		424,397		389,419			758,200			723,124
Purchased gas		48,134		30,820			165,557			114,059
Other operation and maintenance		164,475		168,055			334,848			340,105
Depreciation and amortization		50,205		52,532			100,594			103,218
Amortization of stranded costs		67,140		61,453			134,280			122,906
Other taxes		49,258		53,128			102,447			106,506
Income taxes		46,429		42,513			93,559			73,627
Total operating expenses		850,038		797,920			1,689,485			1,583,545
Operating income		131,043		114,948			250,428			219,562
Other income (deductions), net		334		(3,397	)		(1,236	)		(649	)
Operating and other income		131,377		111,551			249,192			218,913
Interest:
Interest on long-term debt		38,168		42,804			78,564			91,140
Interest on debt to associated companies		16,590		15,822			33,030			30,900
Other interest		368		2,707			3,998			5,820
Total interest expense		55,126		61,333			115,592			127,860
Net income	$	76,251	$	50,218		$	133,600		$	91,053
Dividends on preferred stock		405		840			812			1,681
Income available to common shareholder	$	75,846	$	49,378		$	132,788		$	89,372

Condensed Consolidated Statements of Comprehensive Income

(In thousands of dollars)

(UNAUDITED)

	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Net income	$	76,251		$	50,218		$	133,600		$	91,053
Other comprehensive income (loss), net of taxes:
Unrealized gains (losses) on securities		563			(66	)		(700	)		(95	)
Hedging activity		25,569			11,526			27,159			22,219
Change in additional minimum pension liability		—			—			508			—
Reclassification adjustment for gains included in net income		(58	)		(39	)		(1,285	)		(678	)
Total other comprehensive income		26,074			11,421			25,682			21,446
Comprehensive income	$	102,325		$	61,639		$	159,282		$	112,499

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						Six Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Retained earnings at beginning of period	$	530,229		$	260,960		$	473,287		$	220,966
Net income		76,251			50,218			133,600			91,053
Dividends on preferred stock		(405	)		(840	)		(812	)		(1,681	)
Retained earnings at end of period	$	606,075		$	310,338		$	606,075		$	310,338

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)

	September 30,		March 31,
	2005		2005
ASSETS
Utility plant, at original cost:
Electric plant	$	5,504,559	$	5,394,714
Gas plant		1,553,915		1,533,910
Common plant		307,159		337,151
Total utility plant		7,365,633		7,265,775
Less: Accumulated depreciation and amortization		2,161,066		2,108,379
Net utility plant		5,204,567		5,157,396
Goodwill		1,224,025		1,224,025
Pension intangible		40,339		40,339
Other property and investments		55,007		55,048
Current assets:
Cash and cash equivalents		10,805		19,922
Restricted cash		18,489		7,367
Accounts receivable (net of allowances of $119,025 and $126,085, respectively, and including receivables from associated companies of $5,670 and $6,654, respectively)		498,414		571,552
Materials and supplies, at average cost:
Gas storage		118,922		3,498
Other		15,035		17,739
Derivative instruments		45,029		35,326
Prepaid taxes		47,901		44,273
Current deferred income taxes		218,568		307,431
Regulatory asset — swap contracts		324,429		203,558
Other		11,096		9,772
Total current assets		1,308,688		1,220,438
Regulatory and other non-current assets:
Regulatory assets (Note B):
Merger rate plan stranded costs		2,627,528		2,765,392
Swap contracts		424,651		415,394
Regulatory tax asset		79,765		79,933
Deferred environmental restoration costs (Note C)		415,795		431,000
Pension and postretirement benefit plans		532,657		501,358
Additional minimum pension liability		194,118		194,302
Loss on reacquired debt		63,293		67,162
Other		422,137		330,094
Total regulatory assets		4,759,944		4,784,635
Other non-current assets		30,654		36,481
Total regulatory and other non-current assets		4,790,598		4,821,116
Total assets	$	12,623,224	$	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)

	September 30,		March 31,
	2005		2005
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stockholders’ 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)		38,643		12,961
Retained earnings		606,075		473,287
Total common stockholders’ equity		3,761,584		3,603,114
Preferred stockholders’ 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		1,448,794		1,723,569
Long-term debt to affiliates		1,200,000		1,200,000
Total capitalization		6,451,548		6,567,853
Current liabilities:
Accounts payable (including payables to associated companies of $7,701 and $36,440, respectively)		351,085		271,275
Customers’ deposits		27,170		26,900
Accrued interest		81,165		82,945
Short-term debt to affiliates		173,000		400,500
Current portion of swap contracts		324,429		203,558
Current portion of long-term debt		715,420		550,420
Other		76,115		107,871
Total current liabilities		1,748,384		1,643,469
Other non-current liabilities:
Accumulated deferred income taxes		1,708,342		1,711,630
Liability for swap contracts		424,651		415,394
Employee pension and other benefits		485,085		434,855
Additional minimum pension liability		236,198		236,198
Liability for environmental remediation costs (Note C)		415,795		431,000
Nuclear fuel disposal costs		147,756		145,562
Cost of removal regulatory liability		326,208		318,455
Gas futures		121,165		30,772
Other		558,092		583,174
Total other non-current liabilities		4,423,292		4,307,040
Commitments and contingencies (Notes B and C)		—		—
Total capitalization and liabilities	$	12,623,224	$	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 Statements of Cash Flows

(In thousands of dollars)

(UNAUDITED)

	Six Months ended September 30,
	2005			2004
Operating activities:
Net income	$	133,600		$	91,053
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		100,594			103,218
Amortization of stranded costs		134,280			122,906
Provision for deferred income taxes		63,508			51,043
Pension and other benefit plan expense		36,311			39,784
Cash contributed to pension and postretirement benefit plan trusts		(47,500	)		(65,241	)
Changes in operating assets and liabilities:
Decrease in accounts receivable, net		73,138			60,227
Increase in materials and supplies		(112,720	)		(93,868	)
Increase in accounts payable and accrued expenses		48,324			30,792
Decrease in accrued interest		(1,780	)		(7,720	)
Increase in prepaid taxes		(3,628	)		(5,817	)
Other, net		56,374			4,288
Net cash provided by operating activities		480,501			330,665
Investing activities:
Construction additions		(130,268	)		(120,854	)
Change in restricted cash		(11,122	)		9,377
Other investments		85			1,285
Other		(10,001	)		(712	)
Net cash used in investing activities		(151,306	)		(110,904	)
Financing activities:
Dividends paid on preferred stock		(812	)		(1,681	)
Reductions in long-term debt		(110,000	)		(232,380	)
Net change in short-term debt to affiliates		(227,500	)		3,500
Net cash used in financing activities		(338,312	)		(230,561	)
Net decrease in cash and cash equivalents		(9,117	)		(10,800	)
Cash and cash equivalents, beginning of period		19,922			26,840
Cash and cash equivalents, end of period	$	10,805		$	16,040
Supplemental disclosures of cash flow information:
Interest paid	$	117,491		$	136,256
Income taxes paid	$	9,580		$	7,823

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 condensed consolidated balance sheet included in this Form 10-Q is considered unaudited because 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.

Due to weather patterns in the Company’s service territory, electric sales tend to be substantially higher in summer and winter months and gas sales tend to peak in the winter. Notwithstanding other factors, the Company’s quarterly net income will generally fluctuate accordingly. The Company’s earnings for the three-month and six-month periods ended September 30, 2005, therefore, may not be indicative of earnings for all or any part of the balance of the fiscal year.

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

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 (APB) 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 and annual periods beginning after June 15, 2005; however, 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 (FIN 47), “Accounting for Conditional Asset Retirement Obligations.” FIN 47 will result in: (a) more consistent recognition of liabilities relating to asset retirement obligations, (b) more information about expected future cash outflows

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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.

A conditional retirement obligation, which is referred to in SFAS No. 143, “Accounting for Asset Retirement Obligations,” is defined in FIN 47 as 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 has sufficient information to make a reasonable estimate of the fair value of an asset retirement obligation.

FIN 47 will become effective for the Company as of its March 31, 2006 fiscal year end. The Company is currently assessing the impact of the adoption of FIN 47 on its results of operations and 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” defined the requirements for the accounting for and the reporting of a change in accounting principle. SFAS No. 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the period-specific effects of an accounting change on one or more individual prior periods presented, SFAS No. 154 requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement.

SFAS No. 154 becomes effective for fiscal years ending after December 15, 2005, and the Company will adopt it as of its March 31, 2006 fiscal year end.

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 that apply to its regulated operations. SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation,” permits a public utility that is regulated on a cost-of-service basis to defer certain costs it would otherwise charge to expense, if authorized to do so by the regulator. These deferred costs are known as regulatory assets. The Company’s regulatory assets were approximately $5.1 billion as of September 30, 2005 and approximately $5.0 billion as of 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 the prices it will charge for electric service in the future, including the Competitive Transition Charges

9

(CTCs), will be sufficient to recover and earn a return on the Merger Rate Plan’s stranded regulatory assets over their planned amortization periods, assuming no unforeseen reduction in demand or bypass of the CTC exit fees.

The Company’s ongoing electricity business continues to be rate-regulated on a cost-of-service basis under the Merger Rate Plan and, accordingly, the Company continues to apply SFAS No. 71 to it. In addition, the Company’s Independent Power Producer contracts, and the Purchased Power Agreements, which were entered into when the Company exited the power generation business, continue to be the obligations of the regulated business.

The Company is earning a return on most of its regulatory assets under its Merger Rate Plan.

The Company resets its CTC every two years under its Merger Rate Plan. On July 29, 2005, the Company filed for its CTC to be reset in the prices it charges customers beginning January 1, 2006. The CTC reset is intended to account for changes in forecasted electricity and natural gas commodity prices, and the effects those changes have on the Company’s above market payments under legacy power contracts that otherwise would be stranded. In addition, the Company is authorized to recover amounts exceeding $100 million in its deferral accounts (as projected through the end of each two-year CTC reset period). The Company filed a proposal to recover the excess balance of the deferral accounts as of June 30, 2005 of approximately $196 million and a projection of other deferral amounts through the end of the two-year period. The balance in the deferral accounts as of September 30, 2005 subject to recovery is approximately $215 million. This filing is subject to regulatory review and approval by 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 many other industrial companies, the Company’s transmission and distribution business uses or generates 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 the Company is a potentially responsible party under state or federal law for the remediation of an aggregate of approximately 100 sites, including 53 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 previous owners. The Company is currently investigating and remediating, as necessary, the MGP sites and certain other properties under agreements with the EPA and DEC.

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The Company believes that obligations imposed on the Company because of the environmental laws will not have a material impact on its results of operations or its financial condition. The Company’s Merger Rate Plan provides for the continued application of deferral accounting for variations in spending from amounts provided in rates related to these environmental obligations. As a result, the Company has recorded a regulatory asset representing the investigation, remediation and monitoring obligations it will recover from ratepayers.

The Company is pursuing claims against other potentially responsible parties to recover investigation and remediation costs it believes are the obligations of those parties. The Company cannot predict the success of such claims, however. As of September 30, 2005 and March 31, 2005, the Company had accrued liabilities related to its environmental obligations of approximately $416 million and $431 million, respectively, which are included in the Company’s Condensed Consolidated Balance Sheets. The decrease in the accrued liabilities was primarily due to payments made. The potential high end of the range at September 30, 2005 is presently estimated at approximately $543 million.

Legal Matters:

Station Service Charges: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. (Niagara Mohawk Power Corp. v. Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C.)

The most significant action in this matter is a proceeding before the Federal Energy Regulatory Commission (FERC) involving the Company’s complaint against the NRG Affiliates for their failure to pay station service charges which 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 September 30, 2005, the NRG Affiliates owed the Company approximately $46.3 million for station service. On November 19, 2004 and April 22, 2005, the FERC issued orders denying the Company’s complaint and found that the NRG Affiliates do not have to pay state-approved retail rates for station service. The Company has appealed the orders to the U.S. 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 upholds the FERC’s orders, the Company will be permitted to recover these unpaid station service charges under its rate plans.

New York Independent Service Operator Mitigation Error:On March 4, 2005, the 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. The FERC had approved the NYISO’s action, but the Court of Appeals reversed the FERC’s

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decision. On remand, the FERC reinstated the original higher market prices. As a result, the Company received and paid an invoice of approximately $5.2 million from the NYISO in July 2005. Certain generators have filed protests, stating that the NYISO did not correctly calculate the refunds in its report required under the FERC’s March 4, 2005 order. The New York transmission owners, including the Company, also protested the NYISO’s report, on the grounds that the refunds are improper and are premature for procedural reasons. The transmission owners, including the Company, had previously requested rehearing of the March 4 order on the grounds that: (a) it controverted the direction from the Court and (b) the FERC’s prior finding of a market design flaw and its approval of the NYISO’s use of Temporary Extraordinary Procedures to mitigate that design flaw were proper. Several other parties, including various generators, also filed for a rehearing of the March 2005 order. All of these rehearing requests (and other motions) are pending before the FERC. These filings do not affect the Company’s estimate of its total potential loss, which approximates $7 million to $10 million and which includes interest and the invoice already paid as reported in the Company’s Annual Report on Form 10-K for the fiscal year ended March 31, 2005.

Retail Bypass:As discussed in more detail in the Company’s Annual Report on 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 that they should be permitted to bypass the Company’s retail charges. The FERC issued two orders on complaints filed by the Company’s station service customers in December 2003 which allowed 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 filed for rehearing of these orders, and the FERC denied these requests in January 2005. The Company 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 has appealed the order to the U.S. Court of Appeals for the District of Columbia Circuit on July 9, 2004.

The Court has consolidated these appeals for hearing. The Company filed its brief with the Court on September 22, 2005. The schedule for arguments has not yet been set.

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 the FERC’s station service rulings as part of its deferral recovery proposal made with the PSC on

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July 29, 2005. The Company’s deferral recovery is subject to regulatory review and approval by the PSC.

NOTE D — SEGMENT INFORMATION

Segmental information is presented in accordance with the management responsibilities and economic characteristics of the Company’s business activities. The Company is primarily engaged 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. The Company’s reportable segments are electricity-transmission, electricity-distribution, and gas-distribution. Certain information regarding the Company’s segments is set forth in the following tables. 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-Distribution
			Stranded Cost					Gas-		Electric -		Total
	Distribution		Recoveries			Total		Distribution		Transmission		Segments
Three Months Ended September 30, 2005
Operating revenue	$	664	$	152		$	816	$	94	$	71	$	981
Operating income before income taxes		89		54			143		1		33		177
Depreciation and amortization		33		—	��		33		9		8		50
Amortization of stranded costs		—		67			67		—		—		67
Three Months Ended September 30, 2004
Operating revenue	$	668	$	99		$	767	$	79	$	66	$	912
Operating income before income taxes		73		55			128		—		29		157
Depreciation and amortization		34		—			34		10		9		53
Amortization of stranded costs				61			61		—		—		61
Six Months Ended September 30, 2005
Operating revenue	$	1,248	$	276		$	1,524	$	282	$	134	$	1,940
Operating income before income taxes		178		83			261		24		59		344
Depreciation and amortization		65		—			65		19		17		101
Amortization of stranded costs		—		134			134		—		—		134
Six Months Ended September 30, 2004
Operating revenue	$	1,251	$	191		$	1,442	$	233	$	128	$	1,803
Operating income before income taxes		137		77			214		25		54		293
Depreciation and amortization		67		—			67		19		17		103
Amortization of stranded costs		—		123			123		—		—		123

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(in millions of dollars)
	Electric-Distribution
			Stranded Cost				Gas-		Electric -				Total
	Distribution		Recoveries		Total		Distribution		Transmission		Corporate		Segments
September 30, 2005
Goodwill	$	706	$	—	$	706	$	215	$	303	$	—	$	1,224
Total assets		5,126		3,425		8,551		2,040		1,572		460		12,623
March 31, 2005
Goodwill	$	706	$	—	$	706	$	215	$	303	$	—	$	1,224
Total assets		5,193		3,402		8,595		1,819		1,557		547		12,518

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NOTE E — ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

	Unrealized									Total
	Gain (Loss)			Additional						Accumulated
	On			Minimum						Other
	Available-for-Sale			Pension			Cash Flow			Comprehensive
(In thousands of dollars)	Securities			Liability			Hedges			Income (Loss)
Balance as of March 31, 2005	$	1,706		$	(1,557	)	$	12,812		$	12,961
Unrealized loss on securities, net of tax		(700	)		—			—			(700	)
Hedging activity, net of tax		—			—			27,159			27,159
Change in additional minimum pension liability, net of tax		—			508			—			508
Reclassification adjustment for gain included in net income, net of tax		(105	)		—			(1,180	)		(1,285	)
Balance as of September 30, 2005	$	901		$	(1,049	)	$	38,791		$	38,643

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

	For the Six Months
	Ended September 30,
(In thousands of dollars)	2005			2004
Unrealized losses on securities	$	537		$	107
Hedging activities		(17,319	)		(14,405	)
Change in additional minimum pension liability		(339	)		—
	$	(17,121	)	$	(14,298	)

NOTE F — EMPLOYEE BENEFITS

As discussed in the Company’s Annual Report on Form 10-K for the fiscal 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 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 of which is the amount 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 (i.e., 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 employees and their eligible dependents. These benefits are subject to minimum age and service requirements. The health care benefits include medical coverage and prescription drug coverage and are subject to certain limitations, such as deductibles and co-payments.

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The benefit plans’ costs charged to the Company during the three and six month periods ended September 30, 2005 and 2004 include the following:

(In thousands of dollars)							Other Postretirement
For the Three Months Ended	Pension Benefits						Benefits
September 30,	2005			2004			2005			2004
Service cost	$	7,676		$	6,927		$	4,496		$	2,482
Interest cost		18,677			17,906			17,468			15,276
Expected return on plan assets		(16,896	)		(17,033	)		(11,400	)		(11,195	)
Amortization of prior service cost		864			290			3,642			(68	)
Recognized actuarial loss		8,279			7,066			7,212			6,360
Net periodic benefit cost	$	18,600		$	15,156		$	21,418		$	12,855
Settlement loss	$	—		$	185		$	—		$	—

(In thousands of dollars)							Other Postretirement
For the Six Months Ended	Pension Benefits						Benefits
September 30,	2005			2004			2005			2004
Service cost	$	16,242		$	14,471		$	9,443		$	5,027
Interest cost		37,685			35,285			35,260			30,051
Expected return on plan assets		(33,716	)		(33,935	)		(22,910	)		(23,123	)
Amortization of prior service cost		1,727			580			7,284			(133	)
Recognized actuarial loss		17,134			13,233			15,258			12,901
Net periodic benefit cost	$	39,072		$	29,634		$	44,335		$	24,723
Settlement loss	$	—		$	185		$	—		$	—

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;

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(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 September 30, 2005 increased approximately $26 million over the comparable period in the prior fiscal year. The increase is primarily due to higher electric margin of approximately $14 million because of warmer summer weather, lower interest costs of approximately $6 million, lower operating and maintenance expense of approximately $4 million related to ongoing cost reductions and efficiencies, lower depreciation expense of approximately $2 million and an approximately $4 million reduction in other taxes. These decreases were offset by an increase in income tax expense of approximately $4 million.

Net income for the six months ended September 30, 2005 increased approximately $43 million over the comparable period in the prior fiscal year. The increase is primarily due to a positive adjustment to electric revenues of approximately $32 million stemming from the recognition of a regulatory asset reflecting our ability to recover a previously fully reserved account receivable and lower interest costs of approximately $12 million. An increase in income tax expense of approximately $20 million was offset by higher electric margin of approximately $10 million associated with warmer summer weather than experienced in the previous year, lower operating and maintenance expense of approximately $5 million related to ongoing cost reductions and efficiencies and lower taxes (other than income taxes) of approximately $4 million because of lower gross receipts tax caused by lower tax rates and reduced tax base.

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REVENUES

Electric revenuesfor the three and six months ended September 30, 2005 increased approximately $53 million and $88 million, respectively, over the comparable periods of fiscal 2005. The following table shows the contributing factors to these increases:

Period ended September 30, 2005
(In millions of dollars)
	Three			Six
	Months			Months
Estimated weather impact	$	27		$	27
Purchased power recovery		35			35
Recovery of stranded investment		6			11
Regulatory asset recognition		—			32
Medicare Act tax benefit		(11	)		(11	)
Other		(4	)		(6	)
Total	$	53		$	88

Warmer summer weather than experienced in the previous fiscal year, higher purchased power costs being recovered (see decrease in purchased electricity below), and higher stranded cost revenues all contributed to the increase in revenue for the three and six months ended September 30, 2005. Also contributing to the increase in the six-month period is a one-time recognition of a $32 million regulatory asset related to the recovery of a previously fully reserved station service accounts receivable balance (see the Legal Matters section of Note C for a discussion of station service matters). The increase during the three and six month period was partially offset by a $11 million adjustment to revenues for a regulatory liability related to tax benefits on employee postretirement healthcare benefits created by Medicare prescription drug legislation.

Gas revenuesincreased by $15 million and $49 million in the three and six months ended September 30, 2005, respectively, as compared to the comparable periods in the prior fiscal year. The increase for both the three and six months ended September 30, 2005 is primarily due to higher gas prices passed through to customers and an increase in off-system gas sales. The table below details the components of the fluctuations:

Period ended September 30, 2005
(In millions of dollars)
	Three			Six
	Months			Months
Cost of purchased gas	$	17		$	51
Delivery revenue		(2	)		(2	)
Total	$	15		$	49

The volume of gas sold for the three months ended September 30, 2005, excluding transportation of customer-owned gas, decreased 0.169 million Dekatherms (Dth), or 4.7%, from the comparable period in the prior fiscal year.

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The volume of gas sold for the six months ended September 30, 2005, excluding transportation of customer-owned gas, increased 0.309 million Dth, or 2.0%, from the comparable period in the prior fiscal year. The increase is primarily due to higher overall demand because of colder weather in the first three months of the current fiscal year as compared to the prior fiscal year. Usage for the six months ended September 30, 2005, adjusted for normal weather, decreased 0.533 million Dth, or 3.3%.

OPERATING EXPENSES

Purchased electricityincreased approximately $35 million for both the three and six months ended September 30, 2005, respectively, as compared to the comparable periods in the prior fiscal year. Electricity prices increased 21 % and 24 %, respectively, for the three and six months ended September 30, 2005 as compared to the prior fiscal year, offset by decreases in the volume of electricity purchased for the three and six months ended September 30, 2005 of 0.9 billion kWh, or 13%, and 1.9 billion kWh, or 12%, respectively, as compared to the comparable periods in the prior fiscal year. The decrease in kWh was due to customers that have been migrating to competitive suppliers for their commodity requirements. These costs do not affect electric margin or net income because the Company’s rate plan allows full recovery from customers.

Purchased gasexpense increased approximately $17 million and $51 million for the three and six months ended September 30, 2005, respectively, as compared to the comparable periods in the prior fiscal year. Contributing to the increase of $17 million in the three months ended September 30, 2005 was an increase in gas prices of approximately $3 million and an increase of approximately $15 million related to gas purchased for off-system sales. These increases were partially offset by a decrease in volumes purchased for system customers of approximately $1 million. Contributing to the increase of $51 million for the six months ended September 30, 2005 was an increase of approximately $21 million in gas prices, an increase of approximately $4 million in volumes to system customers, and an increase of approximately $26 million related to gas purchased for off-system sales. These costs do not affect gas margin or net income because the Company’s rate plan allows full recovery from customers.

Other operation and maintenance expensedecreased approximately $4 million and $5 million for the three and six months ended September 30, 2005, respectively, as compared to the comparable periods in the prior fiscal year. The table below details the components of the fluctuations.

(In millions of dollars)

	Three			Six
	Months			Months
Staffing costs		(4	)		(9	)
Materials		(7	)		(3	)
Consultants & Contractors		(3	)		(7	)
Other		(4	)		—
Subtotal	$	(18	)	$	(19	)
2004 Pension settlement loss recovery		14			14
Total	$	(4	)	$	(5	)

Ongoing other operation and maintenance expenses have decreased by $18 million and $19 million, respectively, for the three and six months ended September 30, 2005 as compared to the same periods in the prior year. The decreases are primarily a result in reductions in staffing costs, materials, consultants and contractors reflecting employee attrition and ongoing reduced costs from merger-related efficiencies. Offsetting these decreases is a $14 million pension settlement loss recovery recorded in the prior year reflecting the July 2004 approval by the PSC for the Company to recover a portion of a $30 million pension settlement loss incurred in fiscal 2003. The Company did not record a similar benefit in the current year. 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.

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Amortization of stranded costsincreased approximately $6 million and $11 million for the three and six months ended September 30, 2005, 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 31, 2002, the stranded investment balance is amortized unevenly at levels that increase over the ten-year term of the plan ending December 31, 2011. The increases in the amortization of stranded costs are included in the Company’s rates and do not impact net income.

Other taxesdecreased approximately $4 million for both the three and six months ended September 30, 2005, respectively, as compared to the comparable periods in the prior fiscal year. This decrease is primarily due to a reduction in gross receipts tax due to lower tax rates and reduced tax base, offset by a slight increase in property taxes.

Income taxesincreased approximately $4 million and $20 million for the three and six months ended September 30, 2005, respectively, as compared to the comparable periods in the prior year. This is primarily due to higher book taxable income, partially offset by a tax benefit for both periods due to the enactment of the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

NON-OPERATING EXPENSES

Interest chargesdecreased $6 million and $12 million for the three and six months ended September 30, 2005, respectively, as compared to the comparable periods in the prior year. The decrease in interest charges is attributable to long-term debt maturing in addition to early redemption of third party debt using affiliated company debt at lower interest rates, partially offset by increased interest payments on short-term debt due to higher interest rates.

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”.)

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Short-term liquidity.At September 30, 2005, the Company’s principal sources of liquidity included cash and cash equivalents of approximately $11 million and accounts receivable of approximately $498 million. The Company has a negative working capital balance of approximately $440 million primarily due to long-term debt payments due within one year of approximately $715 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.

Net cash provided by operating activitiesincreased approximately $150 million for the six months ended September 30, 2005 from the comparable period in the prior fiscal year. The primary reasons for the increase in operating cash flow are increased net income of approximately $43 million, an increase in the provision for deferred income taxes of approximately $12 million, lower contributions to employee retirement plans of approximately $18 million, lower accounts payable payments of approximately $18 million, an increase in amortization of stranded costs of approximately $11 million, an increase for the tax benefit related to the Medicare Act of approximately $14 million and other noncash items of approximately $34 million.

Net cash used in investing activitiesincreased by approximately $40 million for the six months ended September 30, 2005 from the comparable period in the prior fiscal year. This increase was primarily due to an increase in construction additions of approximately $9 million, an increase in required deposits to restricted cash of approximately $12 million, and an increase in other investing activities of approximately $10 million primarily due to the disposal of assets.

Net cash used in financing activitiesincreased approximately $108 million for the six months ended September 30, 2005 from the comparable period in the prior year. This increase is primarily due to payments on short-term debt to affiliates of approximately $228 million offset by a decrease in payments of long-term debt of approximately $122 million.

Long-term liquidity.The Company’s total capital requirements consist of amounts for its construction program, working capital needs and maturing debt issues. See the Company’s Annual Report on Form 10-K for the fiscal year ended March 31, 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

The Company resets its CTC every two years under its Merger Rate Plan. On July 29, 2005, the Company filed for its CTC to be reset in the prices it charges customers beginning January 1, 2006. The CTC reset is intended to account for changes in forecasted electricity and natural gas commodity prices, and the effects those changes have on the Company’s above market payments under legacy power contracts that otherwise would be stranded. In addition, the Company is authorized to recover amounts exceeding $100 million in its deferral accounts (as projected through the end of each two-year CTC reset period). The Company filed a proposal to recover the excess balance of the deferral accounts as of June 30, 2005 of approximately $196 million and a projection of other deferral amounts through the

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end of the two-year period. The balance in the deferral accounts as of September 30, 2005 subject to recovery is approximately $215 million. This filing is subject to regulatory review and approval by the 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 September 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.

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, the internal control over financial reporting.

PART II — OTHER INFORMATION

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

	NIAGARA MOHAWK POWER CORPORATION
Date: November 14, 2005	By	/s/ John G. Cochrane
		Chief Financial 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