e10vq

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 December 31, 2005


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.

Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer 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 February 10, 2006, 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.)

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Condensed Consolidated Statements of Operations

(In thousands of dollars)

(UNAUDITED)


	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2005			2004			2005			2004

Operating revenues:
Electric	$	813,104		$	717,812		$	2,470,959		$	2,287,443
Gas		296,181			189,225			578,239			422,700

Total operating revenues		1,109,285			907,037			3,049,198			2,710,143

Operating expenses:
Purchased electricity		373,118			294,447			1,131,318			1,017,571
Purchased gas		219,205			115,356			384,762			229,415
Other operation and maintenance		194,504			183,784			529,352			523,889
Depreciation and amortization		51,764			47,737			152,358			150,955
Amortization of stranded costs		67,140			61,453			201,420			184,359
Other taxes		53,807			55,838			156,254			162,344
Income taxes		30,245			31,811			123,804			105,438

Total operating expenses		989,783			790,426			2,679,268			2,373,971

Operating income		119,502			116,611			369,930			336,172

Other deductions, net		(1,317	)		(2,667	)		(2,553	)		(3,315	)

Operating and other income		118,185			113,944			367,377			332,857

Interest:
Interest on long-term debt		30,415			39,111			108,978			130,251
Interest on debt to associated companies		20,600			17,801			53,630			48,701
Other interest		3,866			1,515			7,865			7,335

Total interest expense		54,881			58,427			170,473			186,287

Net income	$	63,304		$	55,517		$	196,904		$	146,570

Dividends on preferred stock		407			841			1,219			2,522

Income available to common shareholder	$	62,897		$	54,676		$	195,685		$	144,048

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


	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2005			2004			2005			2004

Net income	$	63,304		$	55,517		$	196,904		$	146,570

Other comprehensive income (loss), net of taxes:
Investment activity		(156	)		925			(856	)		830
Hedging activity		(9,012	)		(17,593	)		18,147			1,810
Change in additional minimum pension liability		—			—			508			—
Reclassification adjustment for gains included in net income		(21,051	)		(7,107	)		(22,336	)		(4,971	)

Total other comprehensive loss		(30,219	)		(23,775	)		(4,537	)		(2,331	)

Comprehensive income	$	33,085		$	31,742		$	192,367		$	144,239

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

The accompanying notes are an integral part of these financial statements

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Condensed Consolidated Balance Sheets

(In thousands of dollars)

(UNAUDITED)


	December 31,		March 31,
	2005		2005

ASSETS
Utility plant, at original cost:
Electric plant	$	5,578,977	$	5,394,714
Gas plant		1,565,762		1,533,910
Common plant		304,472		337,151

Total utility plant		7,449,211		7,265,775

Less: Accumulated depreciation and amortization		2,215,848		2,108,379

Net utility plant		5,233,363		5,157,396

Goodwill		1,214,576		1,224,025
Pension intangible		40,339		40,339
Other property and investments		45,816		55,048
Current assets:
Cash and cash equivalents		7,784		19,922
Restricted cash		27,663		7,367
Accounts receivable (net of allowances of $130,154 and $126,085, respectively, and including receivables from associated companies of $7,548 and $6,654, respectively)		597,909		571,552
Materials and supplies, at average cost:
Gas storage		109,181		3,498
Other		20,643		17,739
Derivative instruments		34,878		35,326
Prepaid taxes		16,761		44,273
Current deferred income taxes		206,063		307,431
Regulatory asset – swap contracts		305,809		203,558
Other		8,515		9,772

Total current assets		1,335,206		1,220,438

Regulatory and other non-current assets:
Regulatory assets (Note B):
Merger rate plan stranded costs		2,560,388		2,765,392
Swap contracts		355,971		415,394
Regulatory tax asset		80,326		79,933
Deferred environmental restoration costs (Note C)		412,090		431,000
Pension and postretirement benefit plans		545,401		501,358
Additional minimum pension liability		194,118		194,302
Loss on reacquired debt		61,407		67,162
Other		517,381		330,094

Total regulatory assets		4,727,082		4,784,635

Other non-current assets		28,580		36,481

Total regulatory and other non-current assets		4,755,662		4,821,116

Total assets	$	12,624,962	$	12,518,362

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

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Condensed Consolidated Balance Sheets

(In thousands of dollars)

(UNAUDITED)


	December 31,		March 31,
	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)		8,424		12,961
Retained earnings		668,972		473,287

Total common stockholders’ equity		3,794,262		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		1,448,864		1,723,569
Long-term debt to affiliates		1,200,000		1,200,000

Total capitalization		6,484,296		6,567,853

Current liabilities:
Accounts payable (including payables to associated companies of $24,472 and $36,440, respectively)		401,821		271,275
Customers’ deposits		27,589		26,900
Accrued interest		36,482		82,945
Short-term debt to affiliates		740,000		400,500
Current portion of swap contracts		305,809		203,558
Current portion of long-term debt		275,000		550,420
Other		95,370		107,871

Total current liabilities		1,882,071		1,643,469

Other non-current liabilities:
Accumulated deferred income taxes		1,701,326		1,711,630
Liability for swap contracts		355,971		415,394
Employee pension and other benefits		499,517		434,855
Additional minimum pension liability		236,198		236,198
Liability for environmental remediation costs (Note C)		412,090		431,000
Nuclear fuel disposal costs		149,088		145,562
Cost of removal regulatory liability		334,474		318,455
Gas futures		31,068		30,772
Other		538,863		583,174

Total other non-current liabilities		4,258,595		4,307,040

Commitments and contingencies (Notes B and C)

Total capitalization and liabilities	$	12,624,962	$	12,518,362

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

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Condensed Consolidated Statements of Cash Flows

(In thousands of dollars)

(UNAUDITED)


	Nine Months ended December 31,
	2005			2004

Operating activities:
Net income	$	196,904		$	146,570
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		152,358			150,955
Amortization of stranded costs		201,420			184,359
Provision for deferred income taxes		98,456			77,901
Pension and other benefit plan expense		85,666			70,012
Cash contributed to pension and postretirement benefit plan trusts		(95,500	)		(89,751	)
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable, net		(26,357	)		40,730
Increase in materials and supplies		(108,587	)		(73,958	)
Increase in accounts payable and accrued expenses		118,734			4,746
Decrease in accrued interest		(46,463	)		(52,325	)
(Increase) decrease in regulatory assets		(143,867	)		57,922
Other, net		(8,949	)		5,209

Net cash provided by operating activities		423,815			522,370

Investing activities:
Construction additions		(201,948	)		(189,551	)
Change in restricted cash		(20,296	)		(36,373	)
Other investments		9,631			316
Other, net		(11,203	)		3,002

Net cash used in investing activities		(223,816	)		(222,606	)

Financing activities:
Dividends paid on preferred stock		(1,219	)		(2,522	)
Reductions in long-term debt		(550,418	)		(532,620	)
Net change in short-term debt to affiliates		339,500			241,000
Redemption of preferred stock		—			(25,155	)

Net cash used in financing activities		(212,137	)		(319,297	)


Net decrease in cash and cash equivalents		(12,138	)		(19,533	)
Cash and cash equivalents, beginning of period		19,922			26,840

Cash and cash equivalents, end of period	$	7,784		$	7,307




Supplemental disclosures of cash flow information:

Interest paid	$	217,562		$	233,520
Income taxes paid	$	9,580		$	10,642

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

NOTE A – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation:

Niagara Mohawk Power Corporation and subsidiary companies (the Company), in the opinion of management, have included all adjustments (which include normal recurring adjustments) necessary for a fair statement of the results of operations for the interim periods presented. The March 31, 2005 Condensed Consolidated 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. The March 31, 2005 Condensed Consolidated Balance Sheet included in this Form 10-Q is considered unaudited, however, because it does not include all of the footnote disclosures contained in the Company’s Annual Report on 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 nine-month periods ended December 31, 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. In April 2005, however, 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 and will be effective as of April 1, 2006. 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 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 $5.0 billion as of December 31, 2005 and 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 Competitive Transition Charges (CTC), 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 load or bypass of the CTC charges.

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.

On July 29, 2005, the Company filed its biannual CTC reset and deferral account recovery filing to reset rates charged to customers beginning January 1, 2006. The Company resets its CTC every two years under its Merger Rate Plan. 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 Merger Rate Plan allows the Company to recover amounts exceeding $100 million in its deferral accounts (as projected through the end of each two-year CTC reset period through the end of the Merger Rate Plan). On December 27, 2005, the Public Service Commission (PSC) approved the Company’s proposal for the new CTC effective January 1, 2006. The PSC also approved recovery of deferral account amounts of $100 million in 2006 and $200 million in 2007. For 2006, the actual deferral-related surcharge will begin in April 2006, with $100 million to be collected over the last nine months of the 2006 calendar year. An audit of the deferral amount by regulatory Staff is ongoing. The Company will continue to defer costs and revenues, as applicable, through the end of the Merger Rate Plan on December 31, 2011. The Company’s future filings for recovery of deferred amounts are subject to regulatory review and approval.

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 52 which are Company owned. The Company’s most significant liabilities relate to 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.

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 expects to 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 December 31, 2005 and March 31, 2005, the Company had accrued liabilities related to its environmental obligations of $412 million and $431 million, respectively. The decrease in the accrued liabilities was primarily due to payments made for costs which were previously accrued. The high end of the range of potential liabilities at December 31, 2005 is estimated at $539 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 December 31, 2005, the NRG Affiliates owed the Company $48.1 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 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 as discussed below under “Retail Bypass”, 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.

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 with power produced 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 New York Independent System Operator (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 it 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 U.S. Court of Appeals for the District of Columbia Circuit on July 9, 2004.

The Court has consolidated these appeals for hearing, and the parties completed briefing in February 2006. The schedule for arguments has not yet been set.

These 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 included recovery of lost revenues resulting from the FERC’s station service rulings as part of its deferral recovery proposal made with the PSC on July 29, 2005. The Company’s deferral recovery is subject to ongoing audit by the PSC Staff.

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 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 reversed the FERC’s 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. In an order issued November 21, 2005, the FERC denied rehearing requests by several other parties, including various generators, for a rehearing of the March 2005 order. The FERC also set for hearing the issue of the amount and collectibility of the refunds required to be paid and initiated settlement proceedings before a FERC appointed administrative law judge. Settlement negotiations began in December 2005 and are scheduled to continue through February 2006, in an effort to allow the parties to settle the amount of the refund. On January 23, 2006, the FERC issued an order

clarifying that refunds already paid should not be returned or adjusted pending the outcome of the hearing/settlement proceeding. On January 19, 2006, the New York transmission owners and the NYISO individually filed petitions for review with the Court of Appeals of the March 4 and November 21 FERC orders. These developments do not affect the Company’s estimate of its total potential loss as approximately $7 million to $10 million, 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.

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 -
	Distribution		Recoveries		Total		Distribution		Transmission		Total

Three Months Ended December 31, 2005
Operating revenue	$	603	$	148	$	751	$	296	$	62	$	1,109
Operating income before income taxes		58		45		103		25		22		150
Depreciation and amortization		33		—		33		10		9		52
Amortization of stranded costs		—		67		67		—		—		67

Three Months Ended December 31, 2004
Operating revenue	$	528	$	127	$	655	$	189	$	63	$	907
Operating income before income taxes		53		45		98		25		25		148
Depreciation and amortization		30		—		30		9		9		48
Amortization of stranded costs		—		61		61		—		—		61

Nine Months Ended December 31, 2005
Operating revenue	$	1,851	$	424	$	2,275	$	578	$	196	$	3,049
Operating income before income taxes		236		128		364		49		81		494
Depreciation and amortization		97		—		97		29		26		152
Amortization of stranded costs		—		201		201		—		—		201

Nine Months Ended December 31, 2004
Operating revenue	$	1,778	$	318	$	2,096	$	423	$	191	$	2,710
Operating income before income taxes		191		122		313		50		79		442
Depreciation and amortization		97		—		97		28		26		151
Amortization of stranded costs		—		184		184		—		—		184

(in millions of dollars)


	Electric-Distribution
			Stranded Cost				Gas-		Electric -
	Distribution		Recoveries		Total		Distribution		Transmission		Corporate		Total

December 31, 2005
Goodwill	$	697	$	—	$	697	$	215	$	303	$	—	$	1,215
Total assets		5,308		3,257		8,565		2,069		1,589		402		12,625

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

NOTE E – ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

(In thousands of dollars)


	Gain (Loss)									Total
	On			Additional						Accumulated
	Available-			Minimum						Other
	for-Sale			Pension			Cash Flow			Comprehensive
	Securities			Liability			Hedges			Income (Loss)
Balance as of March 31, 2005	$	1,706		$	(1,557	)	$	12,812		$	12,961
Investment activity, net of tax		(856	)		—			—			(856	)
Hedging activity, net of tax		—			—			18,147			18,147
Change in additional minimum pension liability, net of tax		—			508			—			508
Reclassification adjustment for gain included in net income, net of tax		(163	)		—			(22,173	)		(22,336	)

Balance as of December 31, 2005	$	687		$	(1,049	)	$	8,786		$	8,424

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


	For the Nine Months
(In thousands of dollars)	Ended December 31,
	2005			2004

Investment activity	$	570		$	(554	)
Hedging activity		(12,098	)		(1,207	)
Change in additional minimum pension liability		(339	)		—
Reclassification adjustment for gain included in net income		14,891			3,314

	$	3,024		$	1,553

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.

The benefit plans’ costs charged to the Company during the three and nine month periods ended December 31, 2005 and 2004 include the following:


							Other Postretirement
(In thousands of dollars)	Pension Benefits						Benefits
For the Three Months Ended December 31,	2005			2004			2005			2004

Service cost	$	8,121		$	7,521		$	4,722		$	3,740
Interest cost		18,843			17,976			17,630			16,059
Expected return on plan assets		(16,859	)		(16,905	)		(11,455	)		(11,368	)
Amortization of prior service cost		864			808			3,642			2,406
Amortization of net loss		8,567			6,469			7,629			5,604

Net periodic benefit cost	$	19,536		$	15,869		$	22,168		$	16,441


							Other Postretirement
(In thousands of dollars)	Pension Benefits						Benefits
For the Nine Months Ended
December 31,	2005			2004			2005			2004

Service cost	$	24,362		$	21,993		$	14,165		$	8,768
Interest cost		56,527			53,260			52,890			46,110
Expected return on plan assets		(50,573	)		(50,840	)		(34,366	)		(34,492	)
Amortization of prior service cost		2,591			1,388			10,926			2,273
Amortization of net loss		25,701			19,702			22,888			18,505

Net periodic benefit cost	$	58,608		$	45,503		$	66,503		$	41,164


Special termination benefits not included above	$	—		$	185		$	—		$	—

Estimated contributions for this year	$	80,000			N/A		$	24,000			N/A


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

FORWARD-LOOKING INFORMATION

This report and other presentations made by Niagara Mohawk Power Corporation (the Company) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Throughout this report, forward-looking statements can be identified by the words or phrases “will likely result”, “are expected to”, “will continue”, “is anticipated”, “estimated”, “projected”, “believe”, “hopes”, or similar expressions. Although the Company believes that, in making any such statements, its expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Important factors that could cause actual

results to differ materially from those in the forward-looking statements include, but are not limited to, 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 Regulation”, 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 December 31, 2005 increased $8 million over the comparable period in the prior fiscal year. The increase is primarily due to higher electric margin of $14 million stemming from higher delivery-only sales partially due to colder weather than experienced in the same period in the previous fiscal year and also due to other miscellaneous revenues. Also contributing to the increase are lower interest costs of $4 million, lower income and other tax expense of $4 million, and reduced other deductions of $1 million. Offsetting these increases are higher operation and maintenance expenses of $11 million, primarily due to higher materials and supplies and non-recoverable storm-related costs and higher depreciation expense of $4 million.

Net income for the nine months ended December 31, 2005 increased $50 million over the comparable period in the prior fiscal year. The increase is primarily due to a positive adjustment to electric revenues of $32 million stemming from the recognition of a regulatory asset reflecting our ability to recover a previously fully reserved account receivable. Other contributing factors are lower interest costs of $16 million and higher electric margin of $30 million associated with

warmer summer and colder autumn weather than experienced in the previous fiscal year. Offsetting these increases are higher operation and maintenance expense of $5 million partially related to increased non-recoverable storm-related costs, an increase in income and other tax expense of $21 million (excluding gross receipts tax) and higher depreciation expense of $2 million.

REVENUES

Electric revenues for the three and nine months ended December 31, 2005 increased $95 million and $184 million, respectively, over the comparable periods of fiscal 2005. The following table shows the contributing factors to these increases:

Period ended December 31, 2005
(In millions of dollars)


	Three			Nine
	Months			Months
Estimated weather impact	$	5		$	32
Purchased power recovery		79			114
Recovery of stranded investment		6			17
Regulatory asset recognition		—			32
Medicare Act tax benefit		(6	)		(17	)
Other		11			6

Total	$	95		$	184

Warmer summer and colder autumn weather than experienced in the previous fiscal year, higher purchased power costs being recovered (see increase in purchased electricity below), higher stranded cost revenues, and other miscellaneous revenues all contributed to the increase in revenue for the three and nine months ended December 31, 2005. Also contributing to the increase in the nine-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. The increase during the three and nine month period is partially offset by revenue adjustments of $6 million and $17 million , respectively, for a regulatory liability related to tax benefits on employee postretirement healthcare benefits created by Medicare prescription drug legislation.

Gas revenues increased by $107 million and $156 million in the three and nine months ended December 31, 2005, respectively, compared to the same periods in the prior fiscal year. The increase for both the three and nine months ended December 31, 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 December 31, 2005
(In millions of dollars)


	Three Months		Nine Months
Cost of purchased gas	$	104	$	155
Delivery revenue		3		1

Total	$	107	$	156

The volume of gas sold for the three months ended December 31, 2005, excluding transportation of customer-owned gas, increased 0.066 million Dekatherms (Dth), or 0.5% compared to the same period in the prior fiscal year. The increase for the three months ended December 31, 2005 is primarily due to the migration of delivery-only customers back to delivery and sales. Usage for the three months ended December 31, 2005, adjusted for normal weather, increased 0.23 million Dth, or 1.6%.

The volume of gas sold for the nine months ended December 31, 2005, excluding transportation of customer-owned gas, increased 0.376 million Dth, or 1.3%, compared to the same period in the prior fiscal year. The increase for the nine months ended December 31, 2005 is partially due to higher overall demand because of colder weather when compared to the prior fiscal year and partially due to the migration of delivery-only customers back to being delivery and commodity customers. Usage for the nine months ended December 31, 2005, adjusted for normal weather, decreased 0.302 million Dth, or 1.0%.

OPERATING EXPENSES

Purchased electricity increased by $79 million and $114 million in the three and nine months ended December 31, 2005, respectively, compared to the same periods in the prior fiscal year. Electricity prices increased 33% and 27%, respectively, for the three and nine months ended December 31, 2005 compared to the same periods in the prior fiscal year, offset by decreases in the volume of electricity purchased for the three and nine months ended December 31, 2005 of 0.4 billion kWh, or 6%, and 2.5 billion kWh, or 12%, respectively, compared to the same periods in the prior fiscal year. The decrease in kWh is primarily 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 gas expense increased $104 million and $155 million for the three and nine months ended December 31, 2005, respectively, compared to the same periods in the prior fiscal year. Contributing to the increase of $104 million in the three months ended December 31, 2005 is an increase in gas prices of $63 million, an increase of $1 million related to increased volume of gas sold and an increase of $34 million related to gas purchased for off-system sales. Contributing to the increase of $155 million for the nine months ended December 31, 2005 was an increase of $84 million in gas prices, an increase of $4 million in volumes to system customers and an

increase of $60 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 expense increased $11 million and $5 million for the three and nine months ended December 31, 2005, respectively, over the comparable periods of fiscal 2005. The table below details the components of the fluctuations.

Period ended December 31, 2005
(In millions of dollars)


	Three			Nine
	Months			Months

Storm-related costs	$	3		$	8
Payroll costs, excluding storm-related		—			(11	)
Materials and supplies		5			2
Consultants and contractors		(4	)		(11	)
Other		7			3

Subtotal		11			(9	)

2004 pension settlement loss recovery		—			14

Total	$	11		$	5

The increase for the three months ended December 31, 2005 is primarily due to higher non-recoverable storm-related costs, higher materials and supplies expense, higher bad debt expense and increased other expenses offset, in part, by lower expenses for consultants and contractors reflecting ongoing reduced costs from merger-related efficiencies.

Other operation and maintenance expense for the nine-month period ended December 31, 2005 decreased by a total of $9 million compared to the same period in the prior fiscal year, excluding a one-time pension settlement loss recovery. Contributing to the decrease are reductions in payroll, consultants and contractors and other costs primarily attributable to ongoing reduced costs from merger-related efficiencies. These decreases are offset by increases in materials, storm-related costs and a one-time $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.

Amortization of stranded costs, in accordance with the Merger Rate Plan, increased $6 million and $17 million for the three and nine months ended December 31, 2005, respectively, compared to the same periods in the prior fiscal year. 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 taxes decreased $2 million and $6 million for the three and nine months ended December 31, 2005, respectively, compared to the same 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 taxes decreased $2 million and increased $18 million for the three and nine months ended December 31, 2005, respectively, compared to the same periods in the prior fiscal year. Income tax expense increased in each period due to higher taxable income which is offset, in whole or in part, by a $4 million benefit related to prior years’ tax return true-ups and settlements of tax audits.

NON-OPERATING EXPENSES

Interest charges decreased $4 million and $16 million for the three and nine months ended December 31, 2005, respectively, compared to the same periods in the prior fiscal year. The decrease in interest charges is attributable to maturing long-term debt replaced with affiliated company debt carrying 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”.)

Short-term liquidity. At December 31, 2005, the Company’s principal sources of liquidity included cash and cash equivalents of $8 million and accounts receivable of $598 million. The Company has a negative working capital balance of $547 million primarily due to short-term debt to affiliates of $740 million and long-term debt payments due within one year of $275 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 activities decreased $99 million for the nine months ended December 31, 2005 from the comparable period in the prior fiscal year. The primary reasons for the decrease in operating cash flow are increased accounts receivable of $67 million and increased regulatory assets of $202 million primarily due to higher commodity prices and timing differences between expenditures and cost recovery from customers. These were offset by an increase in net income of $50 million, increases in accounts payable and accrued expenses of $114 million due to increased commodity liabilities and increases in other non-cash items of $6 million.

Net cash used in investing activities increased by $1 million for the nine months ended December 31, 2005 from the comparable period in the prior fiscal year. This increase was primarily due to an increase in construction additions of $12 million, an increase in other investing activities of $5 million primarily due to the disposal of assets, offset by a decrease in restricted cash deposits of $16 million.

Net cash used in financing activities decreased $107 million for the nine months ended December 31, 2005 from the comparable period in the prior year. This decrease is primarily due to increased borrowings of short-term debt from affiliates of $99 million and the redemption of $25 million of preferred stock in the prior year, offset by increased payments of long-term debt of $17 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

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 nine months ended December 31, 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.


	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		23

Signature		24

Exhibit Index		25
EX-31.1 Certification of Principal Executive Officer
EX-31.2 Certification of Principal Financial Officer
EX-32 Certification Pursuant to 18 U.S.C.1350


	NIAGARA MOHAWK POWER CORPORATION
Date: February 14, 2006	By:	/s/ Paul J. Bailey
		Paul J. Bailey
		Authorized Officer and Controller


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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