Niagara Mohawk Power (NMKBP) 10-Q 2007 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, 2006

OR

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

For the transition period from                    to                    

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yesþ          Noo

Indicate by check mark whether the registrant is 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 filero          Accelerated filero          Non-accelerated filerþ

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

Yeso          Noþ

The number of shares outstanding of each of the issuer’s classes of common stock, as of November 13, 2006, were as follows:

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

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
FORM 10-Q — For the Quarter Ended September 30, 2006

	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		23
Item 4. Controls and Procedures		24
PART II – OTHER INFORMATION
Item 1. Legal Proceedings		24
Item 1A. Risk Factors		24
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		26
Item 3. Defaults upon Senior Securities		26
Item 4. Submissions of Matters to a Vote of Security Holders		26
Item 5. Other Information		26
Item 6. Exhibits		26
Signature		27
Exhibit Index		28
Certification of PEO
Certification of PFO
Certification Pursuant to 18 U.S.C 1350

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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,
	2006			2005		2006			2005
Operating revenues:
Electric	$	889,337		$	893,625	$	1,621,214		$	1,664,455
Gas		90,529			94,056		273,835			282,058
Total operating revenues		979,866			987,681		1,895,049			1,946,513
Operating expenses:
Purchased electricity		380,559			424,397		687,770			758,200
Purchased gas		43,689			48,134		158,218			165,557
Other operation and maintenance		169,068			171,075		343,296			341,448
Depreciation and amortization		52,443			50,205		104,680			100,594
Amortization of stranded costs and rate plan deferrals		98,730			67,140		197,459			134,280
Other taxes		54,631			49,258		114,055			102,447
Income taxes		45,172			46,429		69,735			93,559
Total operating expenses		844,292			856,638		1,675,213			1,696,085
Operating income		135,574			131,043		219,836			250,428
Other income (deductions), net		(2,253	)		334		(3,822	)		(1,236	)
Operating and other income		133,321			131,377		216,014			249,192
Interest:
Interest on long-term debt		24,720			38,168		52,049			78,564
Interest on debt to associated companies		21,662			16,590		43,018			33,030
Other interest		4,715			368		9,754			3,998
Total interest expense		51,097			55,126		104,821			115,592
Net income	$	82,224		$	76,251	$	111,193		$	133,600
Dividends on preferred stock		406			405		812			812
Income available to common shareholder	$	81,818		$	75,846	$	110,381		$	132,788

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

	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Net income	$	82,224		$	76,251		$	111,193		$	133,600
Other comprehensive income (loss), net of taxes:
Unrealized gains (losses) on securities		492			563			221			(700	)
Hedging activity		(18,040	)		25,569			(23,383	)		27,159
Change in additional minimum pension liability		—			—			—			508
Reclassification adjustment for (gains) losses included in net income		(26	)		(58	)		1,568			(1,285	)
Total other comprehensive loss		(17,574	)		26,074			(21,594	)		25,682
Comprehensive income	$	64,650		$	102,325		$	89,599		$	159,282

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,
	2006			2005			2006			2005
Retained earnings at beginning of period	$	817,300		$	530,229		$	788,737		$	473,287
Net income		82,224			76,251			111,193			133,600
Dividends on preferred stock		(406	)		(405	)		(812	)		(812	)
Retained earnings at end of period	$	899,118		$	606,075		$	899,118		$	606,075

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,
	2006		2006
ASSETS
Utility plant, at original cost:
Electric plant	$	5,770,894	$	5,658,705
Gas plant		1,602,270		1,580,204
Common plant		294,524		309,053
Total utility plant		7,667,688		7,547,962
Less: Accumulated depreciation and amortization		2,305,019		2,247,350
Net utility plant		5,362,669		5,300,612
Goodwill		1,214,576		1,214,576
Pension intangible		36,885		36,885
Other property and investments		47,311		47,379
Current assets:
Cash and cash equivalents		47,361		10,847
Restricted cash		149,644		66,393
Accounts receivable (net of allowances of $119,182 and $123,310, respectively, and including receivables from associated companies of $3,900 and $10,238, respectively)		502,248		653,652
Materials and supplies, at average cost:
Gas storage		105,253		23,576
Other		21,216		21,356
Prepaid taxes		5,209		13,847
Current deferred income taxes		134,382		168,354
Regulatory asset – swap contracts		189,296		246,551
Other		54,957		13,979
Total current assets		1,209,566		1,218,555
Regulatory and other non-current assets:
Regulatory assets:
Merger rate plan stranded costs		2,352,559		2,486,590
Swap contracts		157,084		290,902
Regulatory tax asset		107,912		106,624
Deferred environmental remediation costs		409,818		399,630
Pension and postretirement benefit plans		540,211		527,829
Additional minimum pension liability		75,252		75,252
Loss on reacquired debt		55,748		59,521
Other		460,910		499,716
Total regulatory assets		4,159,494		4,446,064
Other non-current assets		30,027		30,744
Total regulatory and other non-current assets		4,189,521		4,476,808
Total assets	$	12,060,528	$	12,294,815

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,
	2006			2006
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)		(26,410	)		(4,816	)
Retained earnings		899,118			788,737
Total common stockholders’ equity		3,989,574			3,900,787
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		1,249,072			1,448,934
Long-term debt to affiliates		1,200,000			1,200,000
Total capitalization		6,479,816			6,590,891
Current liabilities:
Accounts payable (including payables to associated companies of $32,148 and $28,315, respectively)		290,000			275,223
Customers’ deposits		36,946			32,345
Accrued interest		57,976			65,952
Accrued taxes		5,981			75,551
Short-term debt to affiliates		676,500			578,900
Current portion of liability for swap contracts		189,296			246,551
Current portion of long-term debt		200,000			275,000
Hedging instruments		91,530			32,555
Other		97,092			97,284
Total current liabilities		1,645,321			1,679,361
Other non-current liabilities:
Accumulated deferred income taxes		1,694,637			1,687,360
Liability for swap contracts		157,084			290,902
Employee pension and other benefits		600,238			628,850
Liability for environmental remediation costs		409,818			399,630
Nuclear fuel disposal costs		154,332			150,642
Cost of removal regulatory liability		347,928			337,995
Other		571,354			529,184
Total other non-current liabilities		3,935,391			4,024,563
Commitments and contingencies
Total capitalization and liabilities	$	12,060,528		$	12,294,815

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,
	2006			2005
Operating activities:
Net income	$	111,193		$	133,600
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		104,680			100,594
Amortization of stranded costs		197,459			134,280
Provision for deferred income taxes		54,419			63,508
Pension and other benefit plan expense		48,445			36,311
Cash contributed to pension and postretirement benefit plan trusts		(100,330	)		(47,500	)
Changes in operating assets and liabilities:
Net accounts receivable		151,404			73,138
Materials and supplies		(81,537	)		(112,720	)
Accounts payable and accrued expenses		19,186			48,324
Accrued interest and taxes		(77,546	)		(1,780	)
Other, net		27,638			52,746
Net cash provided by operating activities		455,011			480,501
Investing activities:
Construction additions		(145,957	)		(130,268	)
Change in restricted cash		(83,251	)		(11,122	)
Other investments		147			85
Other, net		(11,224	)		(10,001	)
Net cash used in investing activities		(240,285	)		(151,306	)
Financing activities:
Dividends paid on preferred stock		(812	)		(812	)
Reductions in long-term debt		(275,000	)		(110,000	)
Net change in short-term debt to affiliates		97,600			(227,500	)
Net cash used in financing activities		(178,212	)		(338,312	)
Net increase (decrease) in cash and cash equivalents		36,514			(9,117	)
Cash and cash equivalents, beginning of period		10,847			19,922
Cash and cash equivalents, end of period	$	47,361		$	10,805
Supplemental disclosures of cash flow information:
Interest paid	$	114,118		$	117,491
Income taxes paid	$	88,764		$	9,580

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, 2006 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, 2006. The March 31, 2006 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, 2006.

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, 2006 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.

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 Securities and Exchange Commission (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 resulted in a six-month deferral for the Company. The adoption of SFAS No. 123R on April 1, 2006 did not have a material impact on the Company’s results of operations or its financial position.

In July 2006, the FASB issued Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting

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and reporting for uncertainties in income tax law. FIN 48 prescribes a comprehensive model for the financial statement recognition, measurement, presentation and disclosure of uncertain tax positions taken or expected to be taken in income tax returns. The cumulative effect of applying the provisions of this interpretation are required to be reported separately as an adjustment to the opening balance of retained earnings in the year of adoption. FIN 48 is effective for fiscal years beginning after December 15, 2006 and will be effective for the Company in its 2008 fiscal year. The Company is currently evaluating FIN 48 and at this time cannot determine the full impact that the potential requirements may have on its financial statements.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” SFAS No. 158 requires an employer to recognize the plan’s funded status on the balance sheet. SFAS No. 158 is effective for fiscal years ending after December 15, 2006. Under the current rate agreement, the difference between the plans’ funded status and current accrued or prepaid position will be recognized as a regulatory asset upon adoption. The Company is currently evaluating SFAS No. 158, and at this time cannot determine the full impact that the requirements of SFAS No. 158 may have on its financial statements.

In September 2006, the SEC issued Staff Accounting Bulletin (SAB) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” SAB No. 108 requires companies to quantify the impact of correcting misstatements using both an income statement (rollover) approach and a balance sheet (iron curtain) approach. If the misstatement of current year expense is material to the current year, after all of the relevant quantitative and qualitative factors are considered, the prior year financial statements should be corrected. Correcting prior year financial statements for immaterial errors would not require previously filed reports to be amended. The Company is currently evaluating the impact of SAB No. 108 and cannot determine the full impact that the requirements of SAB No. 108 may have on its financial statements.

NOTE B – RATE AND REGULATORY ISSUES

General:The Company’s financial statements conform to generally accepted accounting principles in the United States of America (GAAP), including the accounting principles for rate-regulated entities with respect to its regulated operations. The Company applies the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” In accordance with SFAS No. 71, the Company records regulatory assets (expenses deferred for future recovery from customers) and regulatory liabilities (revenues collected for payment of future expenses or for future return to customers) on the balance sheet. The Company’s regulatory assets were approximately $4.3 billion as of September 30, 2006 and $4.7 billion as of March 31, 2006. These regulatory assets are probable of recovery under the Company’s Merger Rate Plan and Gas Multi-Year Rate and Restructuring Agreement. The Company is earning a return on most of its regulatory assets under its Merger Rate Plan. The Company believes that the prices it will charge for electric service in the future, including the Competitive Transition Charges (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 load or bypass of the CTC charges. The Company’s ongoing electric 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

9

contracts, and the Purchase Power Agreements entered into when the Company exited the power generation business, continue to be the obligations of the regulated business.

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

Deferral Audit: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 a $100 million base threshold in its deferral accounts (as projected through the end of each two-year CTC reset period through the end of the Merger Rate Plan). In the July 29, 2005 filing, the Company included a proposal to recover the excess balance of the deferral accounts as of June 30, 2005 of $196 million ($296 million, less the $100 million base deferral threshold that continues through the end of the Merger Rate Plan) and a projection through the end of the two-year period of $373 million, producing a total projected recoverable balance of $569 million ($669 million, less the $100 million base deferral threshold as of December 31, 2007). On December 27, 2005, the New York 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 calendar year 2006 and $200 million in calendar year 2007. For 2006, the deferral-related surcharge was included in rates beginning in April and the $100 million is being collected over the last nine months of the 2006 calendar year.

An audit of the deferral amount by the Department of Public Service Staff (Staff) has been ongoing for several months and an evidentiary hearing took place before a hearing officer at the PSC to litigate certain issues which could impact the levels in the deferral account. Certain adjustments arising from the Staff’s audit work have been made to the deferral account balances as of June 30, 2005, which are primarily reclassifications from the deferral account to other balance sheet accounts, and the Company and the Staff have each revised their respective positions with regard to certain amounts previously in dispute. The Company has written off approximately $8 million of deferrals to operating expenses. At present, the current amount of the deferral account and projected amounts that remain in dispute is approximately $230 million. The Staff also indicated it had not completed its audit on other deferral account items, and that additional proposed adjustments may be forthcoming. In addition, the Staff proposed to require the write-off of all of the $1.2 billion of goodwill on the Company’s balance sheet associated with the Company’s acquisition by National Grid. Because goodwill is excluded from the Company’s investment base for ratemaking purposes, the Staff’s position on goodwill has no impact on the Company’s future rates. The Company disagrees with the vast majority

10

of the Staff’s proposed adjustments to the deferral accounts and to the write-off of goodwill.

During the evidentiary hearing held in October 2006, the Company and the Staff agreed to enter into non-binding mediation discussions before an administrative law judge from the PSC in an attempt to resolve some or all of the amounts remaining in dispute. Despite its agreement to participate in the mediation process, the Company continues to believe that its accounting for the deferrals is appropriate and will continue to defer costs and revenues, as applicable, through the end of the Merger Rate Plan, subject to regulatory review and approval.

Service Quality Penalties:In connection with its Merger Rate Plan the Company is subject to maintaining certain service quality standards. Service quality measures focus on eleven categories including safety targets related to gas operations, electric reliability measures related to outages, residential and business customer satisfaction, meter reads, customer call response times, and administration of the Low-Income Customer Assistance Program. If a prescribed standard is not satisfied, the Company may incur a penalty, with the penalty amount applied as a credit or refund to customers.

Service quality performance is measured on a calendar year basis, thus the entire year is taken into account when determining whether a penalty has been incurred that would be credited or refunded to customers. Target service levels for the customer service measures and the electric reliability measures are based on performance under all operating conditions. However, exclusions do apply for major storms or abnormal operating conditions such as periods of catastrophe, natural disaster, strike or other unusual events not in the Company’s control.

As of September 30, 2006, the Company has recorded reserves of $2.5 million for service quality penalties for fiscal year 2007. Due to poor weather in October 2006, it has become likely that the Company may incur additional penalties of $9 million to $18 million. Improved performance in the remainder of calendar 2006 and other measures could limit the additional penalties. These amounts are not included in the Company’s results of operations or financial position as of September 30, 2006.

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 businesses use or generate some hazardous and potentially hazardous wastes and by-products. Under federal and state Superfund laws, potential liability for the historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.

The U.S. Environmental Protection Agency (EPA), New York 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 90 sites, including 48 which are Company-owned. The Company’s most significant liabilities relate to former manufactured gas plant (MGP) facilities formerly owned or operated by the

11

Company’s previous owners. The Company is currently investigating and remediating, as necessary, those MGP sites and certain other properties under agreements with the EPA and DEC.

The Company believes that obligations imposed on the Company because of the environmental laws will not have a material result on 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 September 30, 2006 and March 31, 2006, the Company had accrued liabilities related to its environmental obligations of $410 million and $400 million, respectively. The increase in the accrued liabilities was primarily the result of recent remedial studies on several sites which resulted in a recognition of higher expected costs. The high end of the range of potential liabilities at September 30, 2006 is estimated at $529 million.

Nuclear Contingencies:As of September 30, 2006 and March 31, 2006, the Company has a liability of $154 million and $151 million, respectively, in other non-current liabilities for the disposal of nuclear fuel irradiated prior to 1983. In January 1983, the Nuclear Waste Policy Act of 1982 (the Nuclear Waste Act) established a cost of $.001 per kWh of net generation for current disposal of nuclear fuel and provides for a determination of the Company’s liability to the U.S. Department of Energy (DOE) for the disposal of nuclear fuel irradiated prior to 1983. The Nuclear Waste Act also provides three payment options for liquidating such liability and the Company has elected to delay payment, with interest, until the year in which Constellation Energy Group Inc., which purchased the Company’s nuclear assets, initially plans to ship irradiated fuel to an approved DOE disposal facility. Progress in developing the DOE facility has been slow and it is anticipated that the DOE facility will not be ready to accept deliveries until at least 2010.

Legal Matters:

Station Service Cases:A number of generators complained or withheld payments associated with the Company’s delivery of station service to their generation facilities, arguing that they were permitted to bypass its retail charges. The Federal Energy Regulatory Commission (FERC) issued two orders on complaints filed by the Company’s station service customers in December 2003, allowing two generators to net their station service electricity over a 30-day period and to avoid state-authorized charges for deliveries made over distribution facilities. A third order in January 2005 involved affiliates of NRG Energy, Inc. These orders directly conflict with the Company’s state-approved tariffs and the orders of the PSC on station service rates. The effect of these orders is to 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. In the aggregate, the Company is owed approximately $64 million as of September 30, 2006. The Company appealed these orders to the U.S. Court of Appeals for the District of Columbia Circuit, and the matters were consolidated for appeal. On June 23,

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2006, the Court issued a decision upholding the FERC’s orders, and on October 23, 2006, the Court denied the Company’s request for rehearing.

The Court’s order upholding the FERC’s orders allows generators to bypass local distribution company charges (including stranded cost recovery charges) when receiving service through the New York Independent System Operator (NYISO) if the amount of power produced by a generator over a 30-day period exceeds the amount of power taken from the grid. Although the Staff has challenged the Company’s position in its testimony in the deferral account audit case (discussed in Note B), the Company believes that the provision in the rate plan that permits the Company to recover lost revenues resulting from a change in law or regulation would permit it to recover the lost revenues that result from the FERC orders.

NOTE D – SEGMENT INFORMATION

Segmental information is presented in accordance with management responsibilities and the 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 electric-transmission, electric-distribution including stranded cost recoveries associated with the divesture of the Company’s generating assets under deregulation, 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. General corporate expenses, property common to the various segments, and depreciation of such common property have been fully allocated to the segments based on labor or plant, using a percentage derived from total labor or plant amounts charged directly to certain operating expense accounts or certain plant accounts.

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(In millions of dollars)

	Electric-Distribution
			Stranded Cost				Gas-		Electric -		Total
	Distribution		Recoveries		Total		Distribution		Transmission		Segments
Three Months Ended September 30, 2006
Operating revenue	$	755	$	67	$	822	$	91	$	67	$	980
Operating income before income taxes		118		38		156		3		22		181
Depreciation and amortization		33		—		33		10		9		52
Amortization of stranded costs and rate plan deferrals		34		64		98		—		1		99
Three Months Ended September 30, 2005
Operating revenue	$	671	$	152	$	823	$	94	$	71	$	988
Operating income before income taxes		89		54		143		1		33		177
Depreciation and amortization		33		—		33		9		8		50
Amortization of stranded costs and rate plan deferrals		—		67		67		—		—		67
Six Months Ended September 30, 2006
Operating revenue	$	1,359	$	133	$	1,492	$	274	$	129	$	1,895
Operating income before income taxes		143		77		220		20		50		290
Depreciation and amortization		68		—		68		20		17		105
Amortization of stranded costs and rate plan deferrals		68		128		196		—		1		197
Six Months Ended September 30, 2005
Operating revenue	$	1,255	$	276	$	1,531	$	282	$	134	$	1,947
Operating income before income taxes		178		83		261		24		59		344
Depreciation and amortization		65		—		65		19		17		101
Amortization of stranded costs and rate plan deferrals		—		134		134		—		—		134

(In millions of dollars)

	Electric-Distribution
			Stranded Cost				Gas-		Electric -				Total
	Distribution		Recoveries		Total		Distribution		Transmission		Corporate		Segments
September 30, 2006
Goodwill	$	697	$	—	$	697	$	215	$	303	$	—	$	1,215
Total assets		5,342		2,768		8,110		1,981		1,585		385		12,061
March 31, 2006
Goodwill	$	697	$	—	$	697	$	215	$	303	$	—	$	1,215
Total assets		5,316		3,051		8,367		1,931		1,595		402		12,295

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NOTE E – ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

	Gain (Loss)									Total
	On			Additional						Accumulated
	Available-			Minimum						Other
	for-Sale			Pension			Cash Flow			Comprehensive
(In thousands of dollars)	Securities			Liability			Hedges			Income (Loss)
March 31, 2006 balance, net of tax	$	1,136		$	(1,199	)	$	(4,753	)	$	(4,816	)
Unrealized gains (losses) on securities		221			—			—			221
Hedging activity		—			—			(23,383	)		(23,383	)
Reclassification adjustment for (gains) losses included in net income		(103	)		—			1,671			1,568
September 30, 2006 balance, net of tax	$	1,254		$	(1,199	)	$	(26,465	)	$	(26,410	)

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)	2006			2005
Unrealized gains (losses) on securities	$	(147	)	$	467
Hedging activity		15,589			(18,106	)
Change in additional minimum pension liability		—			(339	)
Reclassification adjustment for (gains) losses included in net income		(1,045	)		857
	$	14,397		$	(17,121	)

NOTE F – EMPLOYEE BENEFITS

As discussed in the Company’s Annual Report on Form 10-K for the fiscal year ended March 31, 2006, 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 policy for the retirement plans is determined largely by the Company’s settlement agreements with the PSC and what is recovered in rates. However, the Company will contribute no less than the minimum amounts that are required under the Pension Protection Act of 2006. The pension plan’s assets primarily consist of investments in equity and debt securities. In addition, the Company sponsors a non-qualified plan

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(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 six month periods ended September 30, 2006 and 2005 include the following:

(In thousands of dollars)							Other Postretirement
For the Three Months Ended	Pension Benefits						Benefits
September 30,	2006			2005			2006			2005
Service cost	$	6,310		$	7,676		$	3,838		$	4,496
Interest cost		18,718			18,677			18,633			17,468
Expected return on plan assets		(18,526	)		(16,896	)		(11,075	)		(11,400	)
Amortization of prior service cost		864			864			3,642			3,642
Amortization of net loss		6,847			8,279			6,802			7,212
Net periodic benefit cost	$	14,213		$	18,600		$	21,840		$	21,418

(In thousands of dollars)							Other Postretirement
For the Six Months Ended	Pension Benefits						Benefits
September 30,	2006			2005			2006			2005
Service cost	$	14,801		$	16,242		$	8,886		$	9,443
Interest cost		37,987			37,685			38,028			35,260
Expected return on plan assets		(35,520	)		(33,716	)		(22,866	)		(22,910	)
Amortization of prior service cost		1,727			1,727			7,284			7,284
Amortization of net loss		15,112			17,134			14,935			15,258
Net periodic benefit cost	$	34,107		$	39,072		$	46,267		$	44,335
Estimated contributions for this year	$	208,000			N/A		$	—			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 certain statements that are neither reported financial results nor other historical information. These statements are 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

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expressions. Because these forward-looking statements are subject to assumptions, risks and uncertainties, actual future results may differ materially from those expressed in or implied by such statements. Factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to:

(a)	the impact of further electric and gas industry restructuring;
(b)	changes in general economic conditions in New York;
(c)	federal and state regulatory developments and changes in law, including those governing municipalization and exit fees;
(d)	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;
(e)	timing and adequacy of rate relief;
(f)	failure to achieve reductions in costs or to achieve operational efficiencies;
(g)	failure to retain key management;
(h)	adverse changes in electric load;
(i)	acts of terrorism;
(j)	unseasonable weather, climatic changes or unexpected changes in historical weather patterns; and
(k)	failure to recover costs currently deferred under the provisions of SFAS No. 71 as amended, and the Merger Rate Plan in effect with the PSC.

Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Except as required by law, Niagara Mohawk Power Corporation does not undertake any obligation to revise any statements in this report to reflect events or circumstances after the date of this report.

The Business:The Company’s primary business driver is the long-term rate plan with state regulators through which the Company can earn and retain certain amounts in excess of traditional regulatory allowed returns. The plan provides incentive returns and shared savings allowances which allow the Company an opportunity to benefit from efficiency gains identified within operations. Other main business drivers for the Company include the ability to streamline operations, enhance reliability and generate funds for investment in the Company’s infrastructure.

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, 2006, 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, 2006 increased $6 million compared to the

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same period in the prior fiscal year. This increase is primarily due to reduced interest costs and a reduction in bad debt expense. Partially offsetting these cost reductions were lower sales of both electricity and gas due to more normal weather conditions in the current fiscal year than in the prior fiscal year. See the following discussions of revenues and operating expenses for more detailed explanations.

Net income for the six months ended September 30, 2006 decreased $22 million compared to the same period in the prior fiscal year. This decrease was partly a result of a positive adjustment to electric revenues of $32 million in fiscal year 2006 with no comparable adjustment in the current fiscal year. This adjustment was due to a one-time recognition of a regulatory asset related to the recovery of a previously fully reserved accounts receivable. Also contributing to the decrease to a lesser extent than the three months, were lower sales of both electricity and gas due to more normal weather conditions in the current fiscal year than in the prior fiscal year. Partially offsetting these decreases were reduced interest costs and lower income tax expense. See the following discussions of revenues and operating expenses for more detailed explanations.

REVENUES

Electric

The Company’s electricity business encompasses the transmission and distribution of electricity including stranded cost recoveries. The rates are set based on historical or forecasted costs, and the Company earns a return on its assets, including a return on the “stranded costs” associated with the divestiture of the Company’s generating assets under deregulation. Since the start of electricity deregulation in the state of New York, retail electric customers have been migrating to competitive suppliers for their commodity requirements. Commodity costs are passed through directly to customers.

Electric revenue includes:

• Retail sales- delivery charges and recovery of purchased power costs from customers who purchase their electric supply from the Company.

• Delivery only sales– charges for only the delivery of energy for customers who purchase their power from competitive electricity suppliers.

• Sales for resale – sales of excess electricity to the NYISO at the market price of electricity.

Gas

The Company is also a gas distribution company that services customers in cities and towns in central and eastern New York. The Company’s gas rate plan allows it to recover all commodity costs (i.e., the purchasing, interstate transportation and storage of gas for sale to customers) from customers (similar to the recoverability of purchased electricity).

Gas revenue includes:

• Retail sales – distribution (transportation) of gas and the commodity to customers who purchase their gas supply from the Company.

• Transportation revenue – charges for the transportation of gas to customers who purchase their gas commodity from other suppliers.

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• Off-System Wholesale Sales – sales of gas commodity off its distribution system for resale.

Electric revenuesfor the three and six months ended September 30, 2006 decreased $4 million and $43 million, respectively, over the comparable periods of fiscal 2006.

The decrease of $4 million in electric revenues for the three-month period was primarily the result of migration of customers to competitive suppliers for their commodity requirements and an overall decrease in kWh deliveries of 4.9% due to milder weather than experienced in the prior fiscal year. Also contributing to the decrease in electric revenues were decreases in the costs of electricity that were passed on to customers. These decreases were offset by $34 million of rate plan deferral revenues reflecting recovery of $100 million over the nine-month period ending December 31, 2006. This recovery does not impact net income since the Company recognizes an equal and offsetting amount of amortization expense.

The decrease of $43 million for the six-month period is partly a result of a positive adjustment to electric revenues of $32 million in fiscal year 2006 with no comparable adjustment in the current fiscal year. This adjustment was due to a one-time recognition of a regulatory asset related to the recovery of a previously fully reserved accounts receivable. Also contributing to the decrease in electric revenues was the migration of customers to competitive suppliers for their commodity requirements and an overall decrease in kWh deliveries of 3.7% compared to the same period in the prior fiscal year due to milder weather than experienced in the prior fiscal year. These decreases were offset by $67 million of rate plan deferral revenues and increases in the costs of electricity that were passed on to customers.

Gas revenuesdecreased by $3 million and $8 million in the three and six months ended September 30, 2006, respectively, compared to the same periods in the prior fiscal year.

The decrease for the three months ended September 30, 2006 is due to lower gas prices passed through to customers and a decrease in weather-normalized use per customer for both residential and small commercial customers, which affected delivery service margins.

The decrease for the six months ended September 30, 2006 is also due to a decrease in weather-normalized use per customer for both residential and small commercial customers, which affected delivery service margins, offset by higher gas prices passed through to customers. The table below details the components of the fluctuations:

Period ended September 30, 2006
(In millions of dollars)

	Three			Six
	Months			Months
Cost of purchased gas	$	(4	)	$	(7	)
Delivery revenue		1			(1	)
Total	$	(3	)	$	(8	)

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The volume of gas sold for the three months ended September 30, 2006, excluding transportation of customer-owned gas, remained unchanged compared to the same period in the prior fiscal year. Usage for the three months ended September 30, 2006, adjusted for normal weather, was also approximately equal to the same period in the prior fiscal year.

The volume of gas sold for the six months ended September 30, 2006, excluding transportation of customer-owned gas, decreased 1.2 million Dth, or 8%, compared to the same period in the prior fiscal year. The decrease for the six months ended September 30, 2006 was partially due to a decline in use per customer for residential and small commercial customers. Usage for the six months ended September 30, 2006, adjusted for normal weather, decreased 0.5 million Dth, or 3.4%.

OPERATING EXPENSES

Purchased electricitydecreased by $44 million and $70 million in the three and six months ended September 30, 2006, respectively, compared to the same periods in the prior fiscal year. The decrease for the three-month period was primarily due to a decrease in the volume of electricity purchased by 0.54 billion kWh, or 8.2% compared to the same period in the prior fiscal year, caused by the migration of customers to competitive suppliers for commodity, and a decrease in the price of electricity of 1.85% compared to the prior fiscal year. These costs do not affect electric margin or net income because the Company’s rate plan allows full recovery from customers.

The decrease in the six-month period was primarily due to a decrease in the volume of electricity purchased by 1.2 billion kWh, or 9.6% compared to the same period 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 and decreased demand due to less extreme weather than experienced in the prior fiscal year. This was offset by an increase in the price of electricity of 0.6% compared to the same period in the prior fiscal year. These costs do not affect electric margin or net income because the Company’s rate plan allows full recovery from customers.

Purchased gasexpense decreased $4 million and $7 million for the three and six months ended September 30, 2006, respectively, compared to the same periods in the prior fiscal year. Contributing to the decrease of $4 million in the three months was a decrease in gas prices of $3 million and a decrease of $2 million related to gas purchased for off-system sales. Contributing to the decrease of $7 million for the six months was a decrease of $11 million in volume to system customers and a decrease of $7 million related to gas purchased for off-system sales. These were offset by an increase of $11 million in gas prices. 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 $2 million and increased $2 million for the three and six months ended September 30, 2006, respectively, over the comparable periods of fiscal 2006. The table below details the components of the fluctuations.

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Period ended September 30, 2006
(In millions of dollars)

	Three			Six
	Months			Months
Staffing costs	$	2		$	(1	)
Bad debt expense		(5	)		2
Storm costs		—			(2	)
Consultants and contractors		2			2
Other		(1	)		1
Total	$	(2	)	$	2

The decrease of $2 million for the three months ended September 30, 2006 is primarily due to a reduction in bad debt expense. As a result of improved credit and collections practices, the Company was able to reduce bad debt reserves during the second quarter for certain classes of accounts receivable. This was offset by increases in staffing costs, and increased consultant and contractors costs.

The increase of $2 million for the six-month period ended September 30, 2006 was primarily due to an overall increase in bad debt expense resulting from higher commodity costs included in customers’ bills, and increased consultant and contractors costs. These were offset by a reduction in nonrecoverable storm costs for the period as well as overall lower staffing costs.

Amortization of stranded costs and rate plan deferralsincreased $32 million and $63 million for the three and six months ended September 30, 2006, respectively, compared to the same periods in the prior fiscal year. The increase is primarily due to the amortization of deferral accounts established under the Merger Rate Plan. Beginning April 1, 2006, the Company implemented a $100 million rate increase for the nine-month period ended December 31, 2006 to recover these deferred costs described in “Revenues” above. The Company records an equal amount of amortization expense to offset the increase in electric revenues. Also under the Merger Rate Plan, the stranded investment regulatory asset is amortized unevenly at levels that increase over the ten-year term of the plan ending December 31, 2011. The amortization of stranded costs is scheduled in the Merger Rate Plan to decrease by approximately $2 million for all of fiscal year 2007. The change in the amortization of stranded costs and deferral accounts is included in the Company’s rates and does not impact net income.

Other taxesincreased $5 million and $12 million for the three and six months ended September 30, 2006, respectively, compared to the same periods in the prior fiscal year. This increase is primarily due to a reduction in Power For Jobs tax credits resulting in higher gross receipts tax and an increase in property taxes.

Income taxesdecreased $1 million and $24 million for the three and six months ended September 30, 2006, respectively, compared to the same periods in the prior fiscal year. The decreases for both periods were primarily due to lower book pretax income.

NON-OPERATING EXPENSES

Interest chargesdecreased $4 million and $11 million for the three and six months ended September 30, 2006, 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

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company debt carrying lower interest rates, partially offset by increased interest charges due to increased short-term debt at higher interest rates.

LIQUIDITY AND CAPITAL RESOURCES

Short-term liquidity.At September 30, 2006, the Company’s principal sources of liquidity included cash and cash equivalents of $47 million and accounts receivable of $502 million. The Company has a negative working capital balance of $436 million primarily due to short-term debt to affiliates of $677 million, accounts payable of $290 million and long-term debt payments due within one year of $200 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 activitiesdecreased $25 million for the six months ended September 30, 2006 compared to the same period in the prior fiscal year. The primary reasons for the decrease in operating cash flow are a decrease in net income of $22 million, decreased accrued interest and taxes of $76 million, higher cash contributed to pension and post-retirement benefit plan trusts of $53 million. These were offset by a decrease in accounts receivable of $78 million which primarily is due to cash received from a one-time payment related to an outstanding accounts receivable and timing of a receipt related to an asset management contract, a change in materials and supplies of $31 million, and other items of $17 million.

Net cash used in investing activitiesincreased by $89 million for the six months ended September 30, 2006 compared to the same period in the prior fiscal year. This increase was primarily due to an increase in restricted cash of $72 million due to required deposits related to commodity hedges and an increase in construction additions of $17 million.

Net cash used in financing activitiesdecreased $160 million for the six months ended September 30, 2006 compared to the same period in the prior fiscal year. This decrease is primarily due to increased borrowings of short-term debt from affiliates of $325 million, offset by increased payments of long-term debt of $165 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, 2006, 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

Deferral Audit: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

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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 a $100 million base threshold in its deferral accounts (as projected through the end of each two-year CTC reset period through the end of the Merger Rate Plan). In the July 29, 2005 filing, the Company included a proposal to recover the excess balance of the deferral accounts as of June 30, 2005 of $196 million ($296 million, less the $100 million base deferral threshold that continues through the end of the Merger Rate Plan) and a projection through the end of the two-year period of $373 million, producing a total projected recoverable balance of $569 million ($669 million, less the $100 million base deferral threshold as of December 31, 2007). On December 27, 2005, the New York 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 calendar year 2006 and $200 million in calendar year 2007. For 2006, the deferral-related surcharge was included in rates beginning in April and the $100 million is being collected over the last nine months of the 2006 calendar year.

An audit of the deferral amount by the Department of Public Service Staff (Staff) has been ongoing for several months and an evidentiary hearing took place before a hearing officer at the PSC to litigate certain issues which could impact the levels in the deferral account. Certain adjustments arising from the Staff’s audit work have been made to the deferral account balances as of June 30, 2005, which are primarily reclassifications from the deferral account to other balance sheet accounts, and the Company and the Staff have each revised their respective positions with regard to certain amounts previously in dispute. The Company has written off approximately $8 million of deferrals to operating expenses. At present, the current amount of the deferral account and projected amounts that remain in dispute is approximately $230 million. The Staff also indicated it had not completed its audit on other deferral account items, and that additional proposed adjustments may be forthcoming. In addition, the Staff proposed to require the write-off of all of the $1.2 billion of goodwill on the Company’s balance sheet associated with the Company’s acquisition by National Grid. Because goodwill is excluded from the Company’s investment base for ratemaking purposes, the Staff’s position on goodwill has no impact on the Company’s future rates. The Company disagrees with the vast majority of the Staff’s proposed adjustments to the deferral accounts and to the write-off of goodwill.

During the evidentiary hearing held in October 2006, the Company and the Staff agreed to enter into non-binding mediation discussions before an administrative law judge from the PSC in an attempt to resolve some or all of the amounts remaining in dispute. Despite its agreement to participate in the mediation process, the Company continues to believe that its accounting for the deferrals is appropriate and will continue to defer costs and revenues, as applicable, through the end of the Merger Rate Plan, subject to regulatory review and approval.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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There were no material changes in the Company’s market risk or market risk strategies during the six months ended September 30, 2006. For a detailed discussion of market risk, see the Company’s Annual Report on Form 10-K for fiscal year ended March 31, 2006, 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 1. LEGAL PROCEEDINGS

Not applicable.

ITEM 1A. RISK FACTORS

This Report on Form 10-Q contains certain statements that are neither reported financial results nor other historical information. These statements are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Because these forward-looking statements are subject to assumptions, risks and uncertainties, actual future results may differ materially from those expressed in or implied by such statements. We have identified the following risk factors that could have a material adverse effect on our business, financial condition, results of operations or future prospects, or your investment in our securities. Not all of these factors are within our control. In addition, other factors besides those listed below may have an adverse effect on the Company. Any forward-looking statements should be considered in light of these risk factors and the cautionary statement set out at the beginning of Management’s Discussion and Analysis on page 16 of this report.

Regulatory and environmental risks

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Changes in law or regulation could have an adverse effect on our results of operations.

Our business is heavily regulated, and changes in law or regulation could adversely affect us. Regulatory decisions concerning, for example, whether licenses or approvals to operate are renewed and the level of permitted revenues could have an adverse impact on our results of operations, cash flows and financial condition. Our rate plan provides for deferral and recovery of the effects of any externally imposed accounting changes, and changes in federal and state rates, laws, regulations and precedents governing taxes that increase or decrease our costs or revenues from electric operations by more than $2 million per year, or by an amount that exceeds 1% of annual gas earnings. However, these deferred amounts are subject to regulatory review and audit. Approximately $230 million is currently in dispute regarding amounts already deferred and projected to be deferred, as discussed in more detail in Note B to the Financial Statements.

Breaches of or changes in environmental or health and safety laws or regulations could expose us to claims for financial compensation and adverse regulatory consequences, as well as damaging our reputation.

Aspects of our activities are potentially dangerous, such as the operation and maintenance of electricity lines and the transmission and distribution of natural gas. Energy delivery companies also typically use and generate in their operations hazardous and potentially hazardous products and by-products. In addition, there may be other aspects of our operations that are not currently regarded or proved to have adverse effects but could become so, for example, the effects of electric and magnetic fields. We are subject to laws and regulations relating to pollution, the protection of the environment and how we use and dispose of hazardous substances and waste materials. We are also subject to laws and regulations governing health and safety matters including air quality, water quality, waste management, natural resources and the health and safety of the public and our employees. Any breach of these obligations, or even incidents relating to the environment or health and safety that do not amount to a breach, could adversely affect the results of operations and our reputation.

Changes to the regulatory treatment of commodity costs may have an adverse effect on the results of operations.

Changes in commodity prices could potentially affect our energy delivery businesses. Our rate plan permits us to pass through virtually all of the increased costs related to commodity prices to consumers. However, if this ability were restricted, it could have an adverse effect on our operating results.

Operational risks

Network failure or the inability to carry out critical non-network operations may have significant adverse impacts on both our financial position and our reputation.

We may suffer a major network failure or may not be able to carry out critical non-network operations. Operational performance could be adversely affected by a failure to maintain the health of the system or network, inadequate forecasting of demand or inadequate record keeping. This could cause us to fail to meet agreed standards, and even incidents that do not amount to a breach could result in adverse regulatory action and financial consequences, as well as harming

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our reputation. In addition to these risks, we are subject to other risks that are largely outside of our control such as the impact of weather or unlawful acts of third parties. Weather conditions can affect financial performance, and severe weather that causes outages or damages infrastructure will adversely affect operational and potentially, business performance. Terrorist attack, sabotage or other intentional acts may also physically damage our infrastructure or otherwise significantly affect our activities and, as a consequence, affect the results of operations.

Our reputation may be harmed if customers suffer a disruption to their energy supply even if this disruption is outside of our control.

We are responsible for transporting available electricity and gas and, for those customers that have not chosen another supplier; we are also responsible for acquiring and providing electricity and gas which we procure from commodity suppliers. However, where there is insufficient supply, no matter the cause, our role is to manage the system safely, which, in extreme circumstances, may require us to disconnect consumers.

Our results of operations depend on a number of factors including performance against regulatory targets and the delivery of anticipated cost and efficiency savings.

Earnings maintenance and growth will be affected by our ability to meet regulatory efficiency targets. To meet these targets, we must continue to improve managerial and operational performance. Under our rate plan, earnings will be affected by our ability to deliver integration and efficiency savings. Earnings also depend on meeting service quality standards. To meet these standards, we must improve service reliability and customer service. If we do not meet these targets and standards, both the results of operations and our reputation may be harmed.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

          The exhibit index is incorporated herein by reference.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report on Form 10-Q for the quarter ended September 30, 2006 to be signed on its behalf by the undersigned thereunto duly authorized.

	NIAGARA MOHAWK POWER CORPORATION
Date: November 13, 2006	By		/s/ Paul J. Bailey
		Paul J. Bailey
		Authorized Officer and Controller and Principal Accounting Officer

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EXHIBIT INDEX

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

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