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, 2006~~
June 30, 2007


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~~	~~15-0265555~~
	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 ~~February 7,~~August 11, 2007, 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.)	~~187,364,863~~

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						Three Months Ended
	December 31,						December 31,						June 30,
	2006			2005			2006			2005			2007			2006

Operating revenues:
Electric	$	797,838		$	815,304		$	2,419,052		$	2,479,759		$	783,536		$	731,877
Gas		205,631			296,181			479,466			578,239			205,529			183,306

Total operating revenues		1,003,469			1,111,485			2,898,518			3,057,998			989,065			915,183

Operating expenses:
Purchased electricity		327,173			373,118			1,014,943			1,131,318			336,425			307,211
Purchased gas		132,665			219,205			290,883			384,762			135,332			114,529
Other operation and maintenance		238,355			196,704			581,651			538,152			191,548			177,065
Depreciation and amortization		52,775			51,764			157,455			152,358			53,993			52,237
Amortization of stranded costs and rate plan deferrals		98,729			67,140			296,188			201,420			120,733			98,729
Other taxes		41,826			53,807			155,881			156,254			55,625			56,587
Income taxes		19,726			30,245			89,461			123,804			14,291			24,563

Total operating expenses		911,249			991,983			2,586,462			2,688,068			907,947			830,921

Operating income		92,220			119,502			312,056			369,930			81,118			84,262
Other deductions, net		(929	)		(1,317	)		(4,751	)		(2,553	)		(1,052	)		(1,569	)

Operating and other income		91,291			118,185			307,305			367,377			80,066			82,693

Interest:
Interest on long-term debt		24,731			30,415			76,780			108,978			22,665			27,329
Interest on debt to associated companies		22,183			20,600			65,201			53,630			18,914			21,356
Other interest		7,100			3,866			16,854			7,865			7,396			5,039

Total interest expense		54,014			54,881			158,835			170,473			48,975			53,724

Net income	$	37,277		$	63,304		$	148,470		$	196,904			31,091			28,969

Dividends on preferred stock		407			407			1,219			1,219			406			406

Income available to common shareholder	$	36,870		$	62,897		$	147,251		$	195,685		$	30,685		$	28,563

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Condensed Consolidated Balance Sheets

(In thousands of dollars)

(UNAUDITED)


	December 31,		March 31,		June 30,		March 31,
	2006		2006		2007		2007

ASSETS
Utility plant, at original cost:
Electric plant	$	5,825,608	$	5,658,705	$	5,898,819	$	5,854,677
Gas plant		1,616,657		1,580,204		1,632,218		1,617,848
Common plant		284,616		309,053		290,059		288,837

Total utility plant		7,726,881		7,547,962		7,821,096		7,761,362
Less: Accumulated depreciation and amortization		2,324,214		2,247,350		2,355,205		2,318,967

Net utility plant		5,402,667		5,300,612		5,465,891		5,442,395

Goodwill		1,214,576		1,214,576		1,291,911		1,242,461
Pension intangible		34,294		36,885
Other property and investments		47,801		47,379		48,378		47,506

Current assets:
Cash and cash equivalents		17,623		10,847		14,809		15,746
Restricted cash		112,899		66,393		83,160		37,648
Accounts receivable (net of allowances of $117,089 and $123,310, respectively, and including receivables from associated companies of $5,570 and $10,238, respectively)		549,439		653,652
Accounts receivable (less reserves of $134,430 and $126,619, respectively, and including receivables from associated companies of $11,621 and $10,232, respectively)						569,054		670,548
Materials and supplies, at average cost:
Gas storage		90,658		23,576		55,382		4,277
Other		23,962		21,356		26,162		27,926
Derivative instruments						—		7,945
Prepaid taxes		84,194		13,847		26,975		75,573
Current deferred income taxes		133,455		168,354		112,839		107,774
Regulatory asset — swap contracts		190,601		246,551
Regulatory asset – swap contracts						215,177		221,540
Other		17,289		13,979		8,309		14,595

Total current assets		1,220,120		1,218,555		1,111,867		1,183,572

Regulatory and other non-current assets:
Regulatory assets:
Merger rate plan stranded costs		2,293,934		2,486,590		2,139,253		2,220,179
Swap contracts		102,825		290,902
Swap contracts regulatory asset						—		46,500
Regulatory tax asset		108,412		106,624		110,660		100,765
Deferred environmental remediation costs		406,045		399,630		397,197		397,407
Pension and postretirement benefit plans		545,444		527,829
Additional minimum pension liability		88,743		75,252
Pension and post-retirement benefit plans						1,020,794		1,028,129
Loss on reacquired debt		53,862		59,521		50,089		51,975
Other		535,599		499,716		306,583		379,257

Total regulatory assets		4,134,864		4,446,064		4,024,576		4,224,212
Other non-current assets		24,356		30,744		25,148		26,609

Total regulatory and other non-current assets		4,159,220		4,476,808		4,049,724		4,250,821

Total assets	$	12,078,678	$	12,294,815	$	11,967,771	$	12,166,755

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Condensed Consolidated Balance Sheets

(In thousands of dollars)

(UNAUDITED)


	December 31,			March 31,			June 30,			March 31,
	2006			2006			2007			2007

CAPITALIZATION AND LIABILITIES
Capitalization:
Common stockholders’ equity:
Common stockholder’s equity:
Common stock ($1 par value)	$	187,365		$	187,365
Authorized — 250,000,000 shares
Issued and outstanding — 187,364,863 shares
Authorized - 250,000,000 shares
Issued and outstanding - 187,364,863 shares							$	187,365		$	187,365
Additional paid-in capital		2,929,501			2,929,501			2,913,384			2,913,384
Accumulated other comprehensive loss		(18,272	)		(4,816	)		(5,854	)		(58	)
Retained earnings		935,988			788,737			998,980			976,688

Total common stockholder’s equity		4,034,582			3,900,787			4,093,875			4,077,379
Preferred stockholder’s equity:
Preferred equity:
Cumulative preferred stock ($100 par value, optionally redeemable)		41,170			41,170
Authorized — 3,400,000 shares
Issued and outstanding — 411,705 shares
Authorized - 3,400,000 shares
Issued and outstanding - 411,715 shares								41,170			41,170
Long-term debt		1,249,142			1,448,934			1,249,247			1,249,194
Long-term debt to affiliates		1,200,000			1,200,000			1,200,000			1,200,000

Total capitalization		6,524,894			6,590,891			6,584,292			6,567,743

Current liabilities:
Accounts payable (including payables to associated companies of $30,192 and $28,315, respectively)		297,850			275,223
Accounts payable (including payables to associated companies of $28,977 and $37,767, respectively)								232,872			330,976
Customers’ deposits		36,920			32,345			37,981			37,819
Accrued interest		33,487			65,952			30,476			56,625
Accrued taxes		3,582			75,551			88,964			30,343
Short-term debt to affiliates		689,300			578,900			460,800			395,300
Current portion of liability for swap contracts		190,601			246,551			215,177			221,540
Current portion of long-term debt		200,000			275,000			—			200,000
Hedging instruments		67,741			32,555
Derivative instruments								28,510			—
Other		111,352			97,284			117,944			105,886

Total current liabilities		1,630,833			1,679,361			1,212,724			1,378,489

Other non-current liabilities:
Accumulated deferred income taxes		1,718,888			1,687,360			1,644,205			1,694,047
Liability for swap contracts		102,825			290,902			—			46,500
Employee pension and other benefits		620,863			621,635			950,775			996,006
Liability for environmental remediation costs		406,045			399,630			397,197			397,407
Nuclear fuel disposal costs		156,218			150,642			160,195			158,196
Cost of removal regulatory liability		350,823			337,995			355,448			350,073
Deferred credits related to income taxes								71,532			—
Other		567,289			536,399			591,403			578,294

Total other non-current liabilities		3,922,951			4,024,563			4,170,755			4,220,523

Commitments and contingencies (Note C)		—			—			—			—

Total capitalization and liabilities	$	12,078,678		$	12,294,815		$	11,967,771		$	12,166,755

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

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

(UNAUDITED)


	Nine Months ended December 31,						Three Months Ended June 30,
	2006			2005			2007			2006

Operating activities:
Net income	$	148,470		$	196,904		$	31,091		$	28,969
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		157,455			152,358			53,993			52,237
Amortization of stranded costs		296,188			201,420
Amortization of stranded costs and rate plan deferrals								120,733			98,729
Provision for deferred income taxes		74,001			98,456			(38,448	)		(8,621	)
Pension and other benefit plan expense		97,012			85,666
Cash contributed to pension and postretirement benefit plan trusts		(146,644	)		(95,500	)
Changes in operating assets and liabilities:
Net accounts receivable		104,213			(26,357	)		101,494			127,544
Materials and supplies		(69,688	)		(108,587	)		(49,341	)		(33,783	)
Accounts payable and accrued expenses		41,270			118,734			(85,884	)		(41,985	)
Accrued interest and taxes		(104,434	)		(46,463	)		53,490			9,770
Pension and other post-retirement benefits								(45,231	)		(20,106	)
Prepaid taxes		(70,347	)		27,512			48,598			13,345
Regulatory assets		(153,159	)		(222,384	)
Other, net		93,237			42,056			62,121			65,646

Net cash provided by operating activities		467,574			423,815			252,616			291,745

Investing activities:
Construction additions		(263,956	)		(201,948	)		(72,582	)		(68,218	)
Change in restricted cash		(46,506	)		(20,296	)		(45,512	)		(31,648	)
Other investments		(10,500	)		9,631			(872	)		508
Other, net		26,906			(11,203	)		319			(4,319	)

Net cash used in investing activities		(294,056	)		(223,816	)		(118,647	)		(103,677	)

Financing activities:
Dividends paid on preferred stock		(1,219	)		(1,219	)		(406	)		(406	)
Reductions in long-term debt		(275,923	)		(550,418	)		(200,000	)		(275,000	)
Net change in short-term debt to affiliates		110,400			339,500
Borrowings of short-term debt to affiliates								98,000			86,000
Repayments of short-term debt to affiliates								(32,500	)		—

Net cash used in financing activities		(166,742	)		(212,137	)		(134,906	)		(189,406	)


Net increase (decrease) in cash and cash equivalents		6,776			(12,138	)
Net decrease in cash and cash equivalents								(937	)		(1,338	)
Cash and cash equivalents, beginning of period		10,847			19,922			15,746			10,847

Cash and cash equivalents, end of period	$	17,623		$	7,784		$	14,809		$	9,509


Supplemental disclosures of cash flow information:
Interest paid	$	193,334		$	217,562		$	80,018		$	86,538
Income taxes paid	$	168,966		$	9,580
Income taxes paid (refund received)							$	(33,120	)	$	11,564

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~~2007 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.~~2007. The ~~March 31, 2006~~June 30, 2007 Condensed Consolidated Balance Sheet included in this Form 10-Q is unaudited, as it does not contain 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.~~2007.

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~~period ended ~~December 31, 2006~~June 30, 2007 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,~~July 2006, 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 and reporting for uncertainties in income tax law. FIN 48 prescribes a comprehensive model for the financial statement recognition, measurement, presentation and disclosure offor uncertain tax positions taken or expected to be taken in income tax returns. The cumulative effect of applying the ~~provisions~~provision of this interpretation ~~are~~is 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. The Company adopted FIN 48 on April 1, 2007. See Note G – Income Taxes.

In September 2006,

the FASB issued Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements,” which provides enhanced guidance for using fair value measurements in financial reporting. While the standard does not expand the use of fair value in any new circumstance, it has applicability to several current accounting standards that require or permit entities to measure assets and ~~will be effective~~liabilities at fair value. This standard defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles in the ~~Company in its 2008 fiscal year.~~United States of America (GAAP) and expands disclosures about fair value measurements. The Company is currently evaluating ~~FIN 48~~SFAS No. 157 and at this time cannot determine the full impact that the potential requirements may have on its financial statements.

~~On September 29, 2006,~~In February 2007, the FASB issued SFAS No. ~~158, “Employers’ Accounting~~159, “The Fair Value Option for ~~Defined Benefit Pension~~Financial Assets and ~~Other Postretirement Plans.~~Financial Liabilities – Including an Amendment of SFAS No. 115.” This ~~standard amends SFAS Nos. 87, 88, 106~~statement permits companies to choose to measure many financial assets and ~~132(R).~~liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS No. ~~158 requires an employer with a defined benefit plan or other postretirement plan to recognize an asset or liability on its balance sheet~~159 is effective for ~~the overfunded or underfunded status of the plan as defined by SFAS No. 158. The Company will adopt this standard as of March 31,~~fiscal years beginning after November 15, 2007. The Company is ~~currently assessing~~evaluating the impact ~~this standard could~~that the adoption of SFAS No. 159 will have on its ~~results of operations and~~ financial position. Based on the current funded status of the plans, the Company expects to recognize an increased liability under the provisions of SFAS No. 158. However, as a result of the New York Public Service Commission’s (PSC) “Statement of Policy and Order Concerning the Accounting and Ratemaking Treatment for Pensions and Postretirement Benefits Other Than Pensions,” the Company has specific recovery of pension and other postretirement expense and anticipates recognizing a regulatory asset.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),~~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 ~~(costs~~(expenses deferred for future recovery from customers) and regulatory liabilities (revenues collected for future payment of ~~future costs~~expenses or for ~~future~~ return to customers) on the balance sheet. The Company’s regulatory assets were approximately ~~$4.3~~$4.2 billion as of ~~December 31, 2006~~June 30, 2007 and ~~$4.7~~$4.4 billion as of March 31, ~~2006.~~2007. These regulatory assets are probable of recovery under the Company’s Merger Rate Plan (MRP) 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.~~MRP. 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~~MRP’s stranded regulatory assets over their planned amortization periods, assuming no unforeseen reduction in load or bypass of the ~~CTC charges.~~CTCs. The Company’s ongoing electric business continues to be rate-regulated on a cost-of-service basis under the ~~Merger Rate Plan~~MRP and, accordingly, the Company continues to apply SFAS No. 71 to it. In addition, the Company’s Independent Power Producer (IPP) 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 ~~net~~ regulatory ~~assets.~~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.
The Company noted no such changes in the regulatory environment that would cause a change in the financial condition and results of operations.

Deferral Audit:~~On July 29, 2005,~~As reported in the ~~Company filed its biannual~~Company’s Form 10K, Niagara Mohawk and the other parties to the deferral audit associated with the Company’s second CTC reset executed and filed with the New York State Public Service Commission (PSC) on March 23, 2007, a Stipulation of the Parties (Stipulation) setting forth the resolution of these issues associated with the deferral audit. PSC approved this stipulation on July 19, 2007 without change.

Certain 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 accountsbalances 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 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 was collected over the last nine months of the 2006 calendar year.

Anremain subject to audit ~~of the deferral amount~~ by the Department of Public Service Staff (Staff) ~~has been ongoing~~. The Stipulation also clarifies going forward procedures for ~~several months~~recording, reporting and ~~an evidentiary hearing took place before a hearing officer at the PSC to litigate~~auditing of certain ~~issues, which could impact the levels~~other deferrals authorized for recovery.

Third CTC reset and Deferral Account filings:The next biannual deferral account filing included in the ~~deferral account. Certain adjustments arising from the Staff’s audit work have been~~third CTC reset was made ~~to the~~on August 1, 2007 for deferral ~~account~~ balances as of June 30, ~~2005, which are primarily reclassifications from the~~2007 and projected deferrals through December 31, 2009. The deferral account recoveries proposed in the third CTC reset are approximately $136 million per year over the two years (approximately $272 million over the two year period). This represents a reduction of $64 million per year over the $200 million per year currently being collected under the second CTC reset. These deferral recoveries are subject to ~~other balance sheet accounts, and the Company and~~audit by 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. As of December 31, 2006, the Company and ~~Staff differ by $230 million~~further updates and adjustments in the ~~amount of actual and forecasted deferral that~~proceeding. Any differences in the deferrals from this approved recovery level would be ~~allowed for recovery as of December 31, 2007. The Staff also proposed positions~~reflected in the next CTC reset that would reduce prospective deferral recoveries. The Staff 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 disagreed with the Staff positions on the deferral account and treatment of goodwill. Evidentiary hearings have been held before an administrative law judge on these issues.takes effect after 2009.

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.~~three prior years. Based on this performance and consistent with the terms of the MRP, the PSC on June 29, 2007 issued a show cause order as to whether the penalty associated with the frequency of outages should be doubled to $8.8 million per year. The Company has ~~recorded service quality penalty expenses of $11 million for the nine months ended December 31, 2006 and $9 million for the same period in the prior fiscal year.~~filed a response, suggesting an alternative approach.

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 9086 sites, including 47 which are Company-owned. The Company’s most significant liabilities relate to former manufactured gas plant (MGP) facilities formerly owned or operated by the Company’s previous owners. The Company is currently investigating and remediating, as necessary, 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~~MRP 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, 2006~~June 30, 2007 and March 31, ~~2006,~~2007, the Company had accrued liabilities related to its environmental obligations of $406 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 recognition of higher expected costs.$397 million. The high end of the range of potential liabilities at ~~December 31, 2006 is~~June 30, 2007, was estimated at ~~$526~~$519 million.

~~Nuclear Contingencies:~~Acquisition:~~As of December 31,~~

In 2006, ~~and March 31, 2006,~~National Grid plc, the ultimate parent of the Company, ~~had~~announced the proposed acquisition of KeySpan Corporation (KeySpan) for $7.3 billion together with the assumption of approximately $4.5 billion of debt. This would significantly expand its operations in the northeastern US as KeySpan is the fifth largest distributor of natural gas in the US and the largest in the northeast US, serving 2.6 million customers in New York, Massachusetts and New Hampshire. KeySpan also operates an electricity transmission and distribution network serving 1.1 million customers in New York under a ~~liability~~long-term contract with the Long Island Power Authority. KeySpan’s other interests include 6.6 GW of ~~$156 million~~generation capacity, together with a small portfolio of non-regulated, energy-related services, and ~~$151 million, respectively,~~strategic investments in ~~other non-current liabilities for~~certain gas pipeline, storage and liquefied natural gas assets. The planned combination of its current US operations with those of KeySpan would result in National Grid plc becoming the ~~disposal~~third largest energy utility in the US.

National Grid plc has made significant progress towards completion of ~~nuclear fuel irradiated prior to 1983. In January 1983,~~this acquisition and has achieved several important milestones. National Grid plc has obtained clearances from 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~~Federal Trade Commission in respect of the ~~Company’s liability~~Hart-Scott-Rodino Antitrust Improvements Act, from the Committee on Foreign Investment in the US and by the Federal Energy Regulatory Commisson (FERC), and received approval from both National Grid plc and KeySpan shareholders. National Grid plc and KeySpan have signed an agreement with the Long Island Power Authority in principle regarding amended contracts, which is subject to approval by the Attorney General of New York. On July 12, 2007, the New Hampshire Public Utilities Commission approved the merger and an associated comprehensive settlement agreement among National Grid plc and its indirect subsidiary Granite State Electric Company, an affiliate of the Company, KeySpan Corporation and its subsidiary EnergyNorth Natural Gas, Inc., Staff of the New Hampshire Public Utilities Commission, and the Office of Consumer Advocate which was submitted to the ~~U.S.~~Commission on May 15, 2007. In New York, a Merger & Gas Revenue Requirement Joint Proposal (Joint Proposal) dated July 6, 2007, was executed by and among KeySpan Corporation, The Brooklyn Union Gas Company d/b/a KeySpan Energy Delivery New York, KeySpan Gas East Corporation d/b/a KeySpan Energy Delivery Long Island, National Grid plc, Niagara Mohawk Power Corporation, the Staff of the New York State Department of Public Service, the New York State Consumer Protection Board, the City of New York, the Natural Resources Defense Council, Pace Energy ~~(DOE)~~Project, the Public Utility Law Project, the Association for Energy Affordability, the ~~disposal~~International Brotherhood of ~~nuclear fuel irradiated prior to 1983. The Nuclear Waste Act also provides three payment options for liquidating such liability~~Electrical Workers, Locals 1049 & 1381, and the ~~Company has elected~~International Brotherhood of Electrical Workers, Local 97 (collectively referred to ~~delay payment, with interest, until~~herein as “the Signatory Parties”), recommending approval of the ~~year in which Constellation Energy Group Inc., which purchased~~merger. The Joint Proposal is subject to the ~~Company’s nuclear assets, initially plans to ship irradiated fuel to an approved DOE disposal facility. Progress in developing~~approval of the ~~DOE facility has been slow~~New York Public Service Commission and ita decision by the New York Public Service Commission on the Joint Proposal is anticipated ~~that the DOE facility will not be ready to accept deliveries until at least 2010.~~on August 22, 2007. Closing is anticipated soon thereafter.

~~Legal Matters:~~

~~Station Service Cases:~~~~A number of generators complained or withheld payments associated~~In connection with the ~~Company’s delivery of station service~~pending acquisition with KeySpan, National Grid and KeySpan are seeking voluntary non-union workforce reductions through the voluntary early retirement offer (VERO) 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 customers700 non-union employees 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. Subsequent to December 2003, FERC issued a third order that involved affiliates of NRG Energy, Inc. These orders directly conflict with the Company’s state-approved tariffs and the ordersselected areas in both companies in June 2007, including employees 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~~Company. Eligible employees must have been working in ~~the filing that was approved by the PSC on November 25, 2003. In aggregate, the Company is owed approximately $62 million~~a targeted area as of ~~December 31, 2006.~~April 13, 2007 and be age 52 or older with seven or more completed years of service as of September 30, 2007. The VERO is contingent upon the closing of the merger. As of the August 8, 2007 enrollment deadline, approximately 82 percent of eligible employees elected to accept the VERO. 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, 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. On January 22, 2007, the Company filed a joint petition for certiorari to the United States Supreme Court requesting the Court to review and reverse the decision of the Court of Appeals.

The Court of Appeals 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) ifcannot reasonably estimate the amount of ~~power produced by a generator over a 30-day period exceeds the amount of power taken over the power grid.~~its VERO-related costs at this time.

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~~properties 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.


	Electric-Distribution
			Stranded Cost				Gas-		Electric -		Total
(In thousands of dollars)	Distribution		Recoveries		Total		Distribution		Transmission			Segments

Three Months Ended:
June 30, 2007
Operating revenue	$	646,821	$	70,782	$	717,603	$	205,529	$	65,933	$	989,065
Operating income before income taxes		27,194		25,911		53,105		19,672		22,632		95,409
Depreciation and amortization		34,898		54		34,952		10,059		8,982		53,993
Amortization of stranded costs and rate plan deferrals		34,650		82,266		116,916		—		3,817		120,733

June 30, 2006
Operating revenue	$	603,789	$	66,225	$	670,014	$	183,521	$	61,648	$	915,183
Operating income before income taxes		27,808		38,964		66,772		18,535		23,518		108,825
Depreciation and amortization		33,690		54		33,744		9,794		8,699		52,237
Amortization of stranded costs and rate plan deferrals		33,999		63,984		97,983		—		746		98,729


	Electric-Distribution
			Stranded Cost				Gas-		Electric -				Total
(In thousands of dollars)	Distribution		Recoveries		Total		Distribution		Transmission		Corporate		Segments

June 30, 2007
Goodwill	$	742,078	$	—	$	742,078	$	227,874	$	321,959	$	—	$	1,291,911
Total assets		5,951,673		2,234,226		8,185,899		2,032,913		1,683,668		65,291		11,967,771

March 31, 2007
Goodwill	$	713,397	$	—	$	713,397	$	219,468	$	309,596	$	—	$	1,242,461
Total assets		6,167,150		2,371,781		8,538,931		1,960,316		1,637,755		29,753		12,166,755

��
Electric — Distribution
(In thousands of dollars) Stranded Cost Gas — Electric — Total
Distribution Recoveries Total Distribution Transmission Segments

Three Months Ended:

December 31, 2006

Operating revenue $ 689,977 $ 47,662 $ 737,639 $ 205,631 $ 60,199 $ 1,003,469
Operating income before income taxes 45,409 28,908 74,317 19,722 17,907 111,946
Depreciation and amortization 34,117 28 34,145 9,866 8,764 52,775
Amortization of stranded costs and rate plan deferrals 33,999 63,984 97,983 — 746 98,729

December 31, 2005

Operating revenue $ 605,730 $ 147,717 $ 753,447 $ 296,181 $ 61,857 $ 1,111,485
Operating income before income taxes 57,557 44,626 102,183 25,424 22,140 149,747
Depreciation and amortization 33,569 55 33,624 9,582 8,558 51,764
Amortization of stranded costs and rate plan deferrals — 67,140 67,140 — — 67,140

Nine Months Ended:

December 31, 2006

Operating revenue $ 2,049,504 $ 180,489 $ 2,229,993 $ 479,466 $ 189,059 $ 2,898,518
Operating income before income taxes 186,319 106,090 292,409 41,918 67,190 401,517
Depreciation and amortization 101,616 111 101,727 29,471 26,257 157,455
Amortization of stranded costs and rate plan deferrals 101,998 191,952 293,950 — 2,238 296,188

December 31, 2005

Operating revenue $ 1,860,288 $ 423,550 $ 2,283,838 $ 578,239 $ 195,921 $ 3,057,998
Operating income before income taxes 235,269 128,056 363,325 49,097 81,312 493,734
Depreciation and amortization 97,795 163 97,958 28,538 25,862 152,358
Amortization of stranded costs and rate plan deferrals — 201,420 201,420 — — 201,420

Electric — Distribution
(In thousands of dollars) Stranded Cost Gas — Electric — Total
Distribution Recoveries Total Distribution Transmission Corporate Segments

December 31, 2006

Goodwill $ 697,279 $ — $ 697,279 $ 214,588 $ 302,709 $ — $ 1,214,576
Total assets 5,365,539 2,634,100 7,999,639 2,037,344 1,602,117 439,578 12,078,678

March 31, 2006

Goodwill $ 697,279 $ — $ 697,279 $ 214,588 $ 302,709 $ — $ 1,214,576
Total assets 5,315,847 3,051,430 8,367,277 1,930,459 1,594,863 402,216 12,294,815

NOTE E ~~— ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)~~– CHANGES IN EQUITY ACCOUNTS

Gain (Loss) Total
On Additional Accumulated
Available- Minimum Other
(In thousands of dollars) for-Sale Pension Cash Flow Comprehensive
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 408 — — 408
Hedging activity — — (27,636 ) (27,636 )
Reclassification adjustment for (gains) losses included in net income (200 ) — 13,972 13,772

December 31, 2006 balance, net of tax $ 1,344 $ (1,199 ) $ (18,417 ) $ (18,272 )


	Gain								Total
	On								Accumulated
	Available-								Other
	for-Sale		Pension			Cash Flow			Comprehensive
(In thousands of dollars)	Securities		Liability			Hedges			Income (Loss)

March 31, 2007 balance, net of tax⁽¹⁾	$	1,456	$	(1,269	)	$	(245	)	$	(58	)
Unrealized gains on securities		351		—			—			351
Hedging activity		—		—			(10,446	)		(10,446	)
Amortization of post-retirement benefit costs				12						12
Reclassification adjustment for losses included in net income		109		—			4,178			4,287

June 30, 2007 balance, net of tax	$	1,916	$	(1,257	)	$	(6,513	)	$	(5,854	)

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



	For the Nine Months						Three Months Ended
	Ended December 31,						June 30,
(In thousands of dollars)	2006			2005			2007			2006

Unrealized gains (losses) on securities	$	(272	)	$	570		$	(234	)	$	181
Hedging activity		18,424			(12,098	)		6,964			3,562
Change in additional minimum pension liability		—			(339	)
Reclassification adjustment for (gains) losses included in net income		(9,181	)		14,891
Amortization of Pension and PBOP costs								(8	)		—
Reclassification adjustment for gains included in net income								(2,858	)		(1,063	)

	$	8,971		$	3,024		$	3,864		$	2,680

As discussed in the Company’s Annual Report on Form 10-K for the fiscal year ended March 31, ~~2006,~~2007, 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 (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~~three-month period ended June 30, 2007 and ~~nine month periods ended December 31,~~ 2006 ~~and 2005~~ include the following:


							Other Postretirement
(In thousands of dollars)	Pension Benefits						Benefits
For the Three Months Ended June 30,	2007			2006			2007			2006

Service cost	$	6,821		$	7,492		$	4,339		$	4,538
Interest cost		16,695			18,285			19,492			18,959
Expected return on plan assets		(18,735	)		(16,121	)		(11,023	)		(11,642	)
Prior service cost		809			819			3,647			3,647
Amortization of net loss		7,416			7,841			8,109			7,894

Net periodic benefit cost	$	13,006		$	18,316		$	24,564		$	23,396


Estimated contributions for fiscal year 2008	$	342,000					$	—

NOTE G – INCOME TAXES

In July 2006, the FASB issued FIN 48. FIN 48 prescribes guidance to address inconsistencies among entities with the measurement and recognition in accounting for income tax positions for financial statement purposes. Specifically, FIN 48 establishes criteria for the timing of the recognition of income tax benefits. FIN 48 requires the financial statement recognition of an income tax benefit when the Company determines that it is more-likely-than-not that the tax position will be ultimately sustained.

The total amount of gross unrecognized tax benefits at March 31, 2007 was $52.5 million. Upon adoption of FIN 48 on April 1, 2007, the Company recorded an adjusting entry for unrecognized tax benefits totaling $71.5 million, of which $17 million had been previously reflected as a deferred tax liability. The adjusting entry also included $49.5 million which was recorded to goodwill because it related to a pre-acquisition period of the Company. Of the total gross unrecognized tax liability, $6.8 million would impact the effective tax rate, if recognized. In addition, the Company has accrued for total interest of $31.1 million, gross. During the quarter ended June 30, 2007, the Company recorded interest expense of $2.6 million, gross.

Effective as of April 1, 2007, the Company recognizes interest accrued related to uncertain tax positions in interest income or interest expense and related penalties, if applicable, in operating expenses. In prior reporting periods, the Company recognized such accrued interest and penalties in income tax expense. No penalties were recognized during the three months ended June 30, 2007.

As of June 30, 2007, the Company is under examination by the Internal Revenue Service (IRS) for the fiscal years ending March 31, 2003 and March 31, 2004. New York State is currently auditing the Company for the fiscal years ending March 31, 2003 through March 31, 2005. The Company expects the IRS to complete their fieldwork on the current audit within the next twelve months. As a result, it expects to pay $2 million of total gross unrecognized tax benefits.

On April 9, 2007, New York State enacted its 2007 — 2008 budget, which included amendments to the state income tax. Those amendments include a reduction in the corporate net income tax rate to 7.1 percent from 7.5 percent, and the adoption of a single sales factor for apportioning taxable income to New York State. Both amendments are effective January 1, 2007. The Company has evaluated the effects of the amendments and believes that the amendments will not have a material effect on its financial position, cash flows or results of operation.

Other Postretirement
(In thousands of dollars) Pension Benefits Benefits
For the Three Months Ended
December 31, 2006 2005 2006 2005

Service cost $ 7,591 $ 8,121 $ 4,443 $ 4,722
Interest cost 18,484 18,843 19,014 17,630
Expected return on plan assets (17,524 ) (16,859 ) (11,433 ) (11,455 )
Amortization of prior service cost 864 864 3,642 3,642
Amortization of net loss 7,871 8,567 7,467 7,629

Net periodic benefit cost $ 17,286 $ 19,536 $ 23,133 $ 22,168

Settlement loss $ 24,221 $ —

Other Postretirement
(In thousands of dollars) Pension Benefits Benefits
For the Nine Months Ended
December 31, 2006 2005 2006 2005

Service cost $ 22,391 $ 24,362 $ 13,329 $ 14,165
Interest cost 56,472 56,527 57,043 52,890
Expected return on plan assets (53,044 ) (50,573 ) (34,300 ) (34,366 )
Amortization of prior service cost 2,591 2,591 10,926 10,926
Amortization of net loss 22,983 25,701 22,402 22,888

Net periodic benefit cost $ 51,393 $ 58,608 $ 69,400 $ 66,503

Settlement loss $ 24,221
Estimated contributions for fiscal year 2007 $ 202,716 $ —

~~Settlement Loss~~
The Company’s pension plan has unrecognized losses as a result of changes in the value of the projected benefit obligation and the plan assets due to experience different from that assumed and from changes in actuarial assumptions. Under SFAS No. 88 “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” the Company recognized a settlement loss of approximately $24 million during the three months ended December 31, 2006 due to plan payouts that exceeded the threshold as prescribed in SFAS No. 88. In a prior period settlement loss, the PSC provided approval for the Company to recover approximately 50% of the incurred pension settlement loss.

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”,~~result,” “are expected ~~to”,~~to,” “will ~~continue”,~~continue,” “is

~~anticipated”, “estimated”, “projected”, “believe”, “hopes”,~~ anticipated,” “estimated,” “projected,” “believe,” “hopes,” or similar 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~~Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” as amended, and the Merger Rate Plan (MRP) in effect with the ~~PSC.~~New York State Public Service Commission (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, ~~the Company~~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,~~2007, 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.

~~were partially offset by decreased staffing costs, reduced bad debt expense and lower~~ income taxes and interest expenses offset by increases in other ~~taxes expense. See the following discussions of revenues~~operation and ~~operating expenses for more detailed explanation.~~

Net income for the nine months ended December 31, 2006 decreased $48 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. The decrease for the nine months was also the result of the pension settlement loss, increased severe storm costs and other increased costs, as well as lower sales of both electricity and gas due to milder weather conditions in the current fiscal year than in the prior fiscal year. Partially offsetting these decreases were reduced interest costs and lower income taxmaintenance expense. See the following discussions of revenues and operating expenses for more detailed explanation.

REVENUES

Electric

The Company’s electricity business encompasses the transmission and distribution of electricity including the recovery of stranded ~~cost recoveries.~~costs. 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”~~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 electric 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~~electricity for customers who purchase their power from competitive electricity suppliers.

	•		Sales for resale —– sales of excess electricity to the ~~NYISO~~New York Independent System Operator at the market price of electricity. Any gains or losses on sales for resale are passed through directly to customers.

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 gas commodity costs (i.e., the purchasing, interstate transportation and storage of gas for sale to customers) from customers (similar to the recovery of purchased electricity).

Gas revenue includes:

	•		Retail sales —– changes for the distribution (transportation) and the purchase 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.

	•		Off-System wholesale sales —– wholesale sales of gas commodity ~~off its~~to entities that are not distribution system ~~for resale.~~customers and not retail gas users.

Electric revenues~~for~~increased $52 million during the three ~~and nine~~ months ended ~~December 31, 2006 decreased $17 million and $61 million, respectively, over~~June 30, 2007 compared to the ~~comparable periods of~~same period in the prior fiscal ~~2006.~~

year. The ~~decrease of $17 million in electric revenues for the three-month period~~increase was primarily ~~the result of the migration of customers~~due to ~~competitive suppliers for their commodity requirements and~~ an overall ~~decrease~~increase in kWh deliveries of ~~2.1% due~~3.4 percent and an increase in the cost of electricity that was passed on to customers. The sales volume increase was primarily a result of milder weather ~~than experienced~~ in the prior fiscal year compared to the same period in the current fiscal year. Also contributing to the ~~decrease in electric revenues were decreases in~~increase was $17 million due to the ~~costs of electricity that were passed on to customers. These decreases were offset by $33 million of rate plan deferral revenues reflecting~~ recovery of the MRP deferral account recovery. In fiscal 2006, the Company implemented a $100 million ~~over~~rate increase during the ~~nine-month~~nine month period ended December 31, ~~2006. This~~2006 to recover MRP deferrals. The Company implemented a second rate increase of $200 million effective January 1, 2007 for calendar year 2007. The increase also includes a $5 million increase in stranded cost revenues reflecting recovery ~~does~~that will continue to occur unevenly at levels that increase over the ten-year term of the plan ending on December 31, 2011. MRP deferral and stranded cost recoveries do not impact net income since the Company recognizes an equal and offsetting amount of amortization expense.

The decrease of $61 million for the nine-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 These increases in electric revenues ~~was~~were partially offset by the ~~migration~~impact of customers migrating to competitive suppliers for their commodity ~~requirements and an overall decrease in kWh deliveries of 3.2%~~requirements.

Gas revenuesincreased by $22 million for the three months ended June 2007, compared to the same period in the prior fiscal ~~year 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 $100 million of rate plan deferral revenues. This recovery does not impact net income since the Company recognizes an equal and offsetting amount of amortization expense.

~~Gas revenues~~~~for the three and nine months ended December 31, 2006 decreased by $91 million and $99 million, respectively, compared to the same periods in the prior fiscal year.~~

The ~~decrease for the three months ended December 31, 2006 is~~increase was primarily due to ~~lower~~increased volumes of gas ~~prices passed through to customers. Delivery revenue decreased by $4 million as a result of an annual reconciliation~~sold both on-system to the ~~Lost~~Company’s system customers and ~~Unaccounted For Gas incentive mechanism. This incentive mechanism provides the Company with an incentive to control Lost and Unaccounted For Gas and is included~~off-system for resale in ~~the Company’s gas rate plan.~~interstate commerce.

The decrease for the nine months ended December 31, 2006 is also primarily due to lower gas prices passed through to customers. In addition, a decrease in weather-normalized use per customer for both residential and small commercial customers resulted in decreased delivery service margins. Delivery revenue decreased by $4 million as a result of an annual reconciliation to the Lost and Unaccounted For Gas incentive mechanism. This incentive mechanism provides the Company with an incentive to control Lost and Unaccounted For Gas and is included in the Company’s gas rate plan. The table below details the components of the fluctuations.

Period Ended December 31, 2006
Three Nine
(In millions of dollars) Months Months

Cost of purchased gas $ (87 ) $ (94 )
Delivery revenue (4 ) (4 )
Other — (1 )

Total $ (91 ) $ (99 )


Change in Gas Revenues
Period Ended June 30, 2007
	Three
(In millions of dollars)	Months

Cost of purchased gas	$	21
Delivery revenue		1

Total	$	22

The volume of gas sold for the three months ended ~~December 31, 2006,~~June 30, 2007, excluding transportation of customer-owned gas, ~~decreased 1.4~~increased 1.5 million Dth, or ~~10.7%~~13.3 percent, compared to the same period in the prior fiscal year. ~~The decrease for~~This increase was primarily due to milder weather in the prior fiscal year as compared to the same period in the current fiscal year.

OPERATING EXPENSES

Purchased electricityincreased by $29 million during the three months ended December 31, 2006 was partially due to a decline in use per customer for residential and small commercial customers. Usage for the three months ended December 31, 2006, adjusted for normal weather, decreased 0.6 million Dth or 3.9%June 30, 2007 compared to the same period in the prior fiscal year.

Of the $29 million increase in purchased electricity, approximately $11 million of the increase was contributed by increased volume and approximately $18 million was contributed by increased purchase price. The increase in the volume of ~~gas sold for~~electricity purchased of 0.2 billion kWh, or 3.6 percent was primarily caused by colder weather in the ~~nine months ended December 31, 2006, excluding transportation of customer-owned gas, decreased 2.7 million Dth, or 9.2%,~~current fiscal year compared to the same period in the prior fiscal year. The decrease for the nine months ended December 31, 2006 was partially due to a decline in use per customer for residential and small commercial customers. Usage for the nine months ended December 31, 2006, adjusted for normal weather, decreased 1.1 million Dth, or 3.6%.

~~OPERATING EXPENSES~~

~~Purchased~~Increased purchased electricitydecreased by $46 million and $116 million in the three and nine months ended December 31, 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 0.2 billion kWh, or 3.6% compared to the same period in the prior fiscal year, caused by the migration of customers to competitive suppliers for commodity requirements and decreased demand due to milder weather than experienced in the prior fiscal year. Also contributing to the decrease was a reduction in the price of electricity of 9.02% 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. The increase in purchased electricity was partially offset by the impact of customer migration for their energy supply.

~~The decrease in~~Purchased gasexpense increased $21 million for the ~~nine-month period was primarily due to a decrease in the volume of electricity purchased by 1.4 billion kWh, or 7.7%~~three months ended June 30, 2007, compared to the same period in the prior fiscal year. ~~The decrease~~This increase was primarily a result of an increase in ~~kWh is primarily due to customers that have been migrating to competitive suppliers for their commodity requirements and decreased demand due to milder weather than experienced in~~ the prior fiscal year. Also contributing to the decrease was a reduction in the price of electricity of 2.78% 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 gas~~expense decreased $87 million and $94 million for the three and nine months ended December 31, 2006, respectively, compared to the same periods in the prior fiscal year. Contributing to the decrease of $87 million in the three months was a decrease in gas prices of $48 million, a decrease of $19 million related to decreased volume of gas purchased ~~to serve~~for system customers and ~~a decrease~~an increase of ~~$20~~$8 million ~~related to gas purchased for off-system sales. Contributing to~~in the ~~decrease~~cost of $94 million for the nine months was a decrease in gas prices of $32 million, a decrease of $36 million related to decreased volume of gas purchased to serve system customers, and a decrease of $26 million related to gas purchased for off-system sales. These costs do not affect gas margin ~~or net income~~ because the Company’s rate plan allows full recovery from customers.

Other operation and maintenance expenseincreased ~~$42 million and $43~~$14 million for the three ~~and nine~~ months ended ~~December 31, 2006, respectively, over~~June 30, 2007 compared to the ~~comparable periods of~~same period in the prior fiscal ~~2006.~~year. The table below details the components of the fluctuations.


Period Ended June 30, 2007
	Three
(In millions of dollars)	Months

Energy management assessments	$	3
Bad debt expense		3
Storm costs		5
Consultants and contractors		3

Total	$	14

Energy management assessments represent amounts assessed by the New York State Energy Research Development Agency for state-wide renewable energy initiatives and electric system benefit programs. Any increases or decreases in these assessments results in an offsetting adjustment to revenues.

1917

Period Ended December 31, 2006
Three Nine
(In millions of dollars) Months Months

Pension settlement loss $ 24 $ 24
Staffing costs (5 ) (7 )
Bad debt expense (8 ) (6 )
Storm costs 9 7
Consultants and contractors 8 10
Service quality penalties 6 2
Rents 1 3
Materials & supplies 2 (1 )
Other 5 11

Total $ 42 $ 43

~~The Company recorded a pension settlement loss~~Bad debt expense increased because of ~~$24 million in its current fiscal quarter associated with pension payouts. For further information, see Note F, Employee Benefits, in Part I, Item 1.~~

~~Staffing costs, excluding storm related costs, have decreased~~higher revenues billed to customers as a result of ~~lower healthcare~~colder February and ~~workers’ compensation and other benefit costs.~~

~~Bad debt expense has decreased as a result of improved collection practices and lower revenues billed to customers.~~March months than in the prior fiscal year.

The Company is allowed to recover from customers the costs of major storms in which the costs and/or number of customers affected exceed certain specified thresholds. Non-recoverable storm costs are composed of: (1) the first $8 million of costs, cumulatively, associated with major storms, and (2) the costs of each storm thereafter that ~~does~~do not qualify as a major storm as defined in the Company’s rate plan. Non-recoverable storm costs increased due to a higher incidence of severe storms that occurred in the current fiscal year as compared to the prior year that did not qualify for recovery from customers. In October 2006, the Company suffered the most significant storm damage it has experienced in Western New York since the Company began serving the area more than 100 years ago. Most of the costs associated with this storm are recoverable. The regulatory asset associated with this storm was $72 million at December 31, 2006.

The increase in consultants and contractor costs is ~~partially~~primarily due to increased tree trimming costs associated with the Company’s reliability improvement program. ~~Also,~~In addition, the Company has been utilizing more external vendors in response to merger integration initiatives.

Service quality penalties have increased in part due to the doubling of the penalty associated with failing to achieve a particular electric reliability measure related to system interruptions. Service quality penalties are described in Note B, Rate and Regulatory Issues in Part 1, Item 1.

Amortization of stranded costs and rate plan deferralsincreased ~~$32~~$22 million ~~and $95 million for~~during the three ~~and nine~~ months ended ~~December 31, 2006, respectively,~~June 30, 2007 compared to the same ~~periods~~period in the prior fiscal year. The increase is primarily due to ~~the amortization of~~increased MRP 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 costsrecoveries and stranded cost revenues as described in ~~“Revenues” above. The Company records an equal amount of amortization expense to offset~~ the ~~increase in~~ electric ~~revenues. Also under~~revenue section. Under the ~~Merger Rate Plan,~~MRP, the stranded ~~investment~~cost regulatory asset is amortized unevenly at levels that increase over the ten-year term of the plan ending on December 31, 2011. The change in the amortization of stranded costs and deferral ~~accounts~~account balance is included in the Company’s ~~rates~~revenues and does not impact net income.

~~Other~~Income taxesdecreased ~~$12~~$10 million ~~and was relatively unchanged~~ for the three ~~and nine~~ months ended ~~December 31, 2006, respectively,~~June 30, 2007 compared to the same ~~periods~~period in the prior fiscal year. The decrease ~~of $12 million~~ was ~~primarily a result of a property tax true-up related to revised estimates.~~

~~Income taxes~~~~decreased $11 million and $34 million for the three and nine months ended December 31, 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 ~~$1 million and $12~~$5 million for the three ~~and nine~~ months ended ~~December 31, 2006, respectively,~~June 30, 2007 compared to the same ~~periods~~period in the prior fiscal year. The decrease ~~in interest charges~~ is ~~attributable~~primarily due to ~~maturing~~decreased long-term debt replaced with affiliated company debt carrying lower interest rates. This is partially offset by increased interest charges due to increased short-term debt at higher interest rates and higher interest rates on the tax-exempt variable rate debt.outstanding.

LIQUIDITY AND CAPITAL RESOURCES

Short-term liquidity.At ~~December 31, 2006,~~June 30, 2007, the Company’s principal sources of liquidity included cash and cash equivalents of ~~$18~~$15 million and accounts receivable of ~~$549~~$569 million. The Company has a negative working capital balance of ~~$411~~$101 million primarily due to short-term debt due to affiliates of ~~$689~~$461 million and accounts payable of ~~$298 million and long-term debt payments due within one year of $200~~$233 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 its debt requirements.

Net cash provided by operating activities~~increased by $44~~were $253 million for the ~~nine~~three months ended ~~December 31,~~June 30, 2007. The primary activities affecting operating cash flows are:

depreciation and amortization of $54 million.

amortization of stranded costs and rate plan deferrals of $121 million in accordance with the MRP.

decrease in accounts receivable of $101 million.

•		increase in accrued interest and taxes of $53 million.

These increases were partially offset by:

increase in materials and supplies of $49 million primarily due to a higher level of gas storage.

decrease in accounts payable and accrued expenses of $86 million.

Net cash used in investing activitieswas $119 million for the three months ended June 30, 2007 compared to $104 million during the same period in the prior fiscal year. This was primarily a result of increases in

construction additions of $73 million at June 30, 2007 compared to $68 million at June 30, 2006 and restricted cash of $46 million at June 30, 2007 compared to $32 million at June 30, 2006.

Net cash used in financing activitieswas $135 million for the three months ended June 30, 2007 compared with $189 million during the same period in the prior fiscal year. The ~~primary reasons for the increase in operating cash flow are a~~ decrease in accounts receivable of $131 million and a change in materials and supplies of $39 million. These were offset by higher cash contributed to pension and postretirement benefit plan trusts of $51 million, decreased accrued interest and taxes of $58 million and various other items totaling $17 million.

~~Net cash used in investing activities~~~~increased by $70 million for the nine months ended December 31, 2006 compared to the same period in the prior fiscal year. This increase~~ was primarily due to ~~an increase in construction additions~~lower debt repayment of ~~$62 million.~~

~~Net cash used in financing activities~~~~decreased $45~~$200 million ~~for the nine months ended December 31, 2006~~at June 30, 2007 compared to ~~the same period in the prior fiscal year.~~$275 million at June 30, 2006. This ~~decrease is due to decreased~~was partially offset by increased repayment on borrowings of short-term debt from affiliates of ~~$229~~$33 million ~~offset by decreased payments of long-term debt of $274 million.~~at June 30, 2007 with no comparable repayment at June 30, 2006.

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,~~2007, Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — ~~“Financial Position, Liquidity~~“Liquidity and Capital Resources” for further information on long-term commitments.

OTHER REGULATORY MATTERS

Deferral Audit:OnAs reported in the Company’s Form 10K, Niagara Mohawk and the other parties to the deferral audit associated with the Company’s Second CTC Reset executed and filed with the New York State Public Service Commission (PSC) on March 23, 2007, a Stipulation of the Parties (Stipulation) setting forth the resolution of these issues associated with the deferral audit. PSC approved this stipulation on July ~~29, 2005, the Company filed its biannual CTC reset and~~19, 2007 without change.

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, and that process is continuing. In the event that a settlement is reached through the mediation process, the settlement would be subject to approval by the Commission.

takes effect after 2009.

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~~three months ended ~~December 31, 2006.~~June 30, 2007. For a detailed discussion of market risk, see the Company’s Annual Report on Form 10-K for fiscal year ended March 31, ~~2006,~~2007, 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, as amended, ~~(i)~~ is recorded, processed, summarized and reported as and when required and ~~(ii)~~ accumulated and communicated to the Company’s management, including the Chief Financial Officer and President, as appropriate, to allow timely decisions regarding disclosure.

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 15 of this report.

Regulatory and environmental risks

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%1 percent of annual gas earnings. However, these deferred amounts are subject to regulatory review and audit. ~~As of December 31, 2006, the Company and Staff differ by $230 million in the amount of actual and forecasted deferral that would be allowed for recovery as of December 31, 2007.~~ This is 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 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;~~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.


				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~~ Management’s Discussion and Analysis of Financial Condition and Results of Operations		15

Item 3. Quantitative and Qualitative Disclosures About Market Risk		19

Item 4. Controls and Procedures		20

PART II – OTHER INFORMATION

Item 3.1. Legal Proceedings		20

~~Quantitative~~Item 1A. Risk Factors		20

Item 2. Unregistered Sales of Equity Securities and ~~Qualitative Disclosures About Market Risk~~Use of Proceeds		22

Item 3. Defaults upon Senior Securities		22

Item 4. Submissions of Matters to a Vote of Security Holders		22

Item 5. Other Information		22

Item 6. Exhibits		22

Signature		23

Exhibit Index
~~Item 4.~~	~~Controls and Procedures~~		23

~~PART II — OTHER INFORMATION~~

~~Item 1.~~	~~Legal Proceedings~~		23

~~Item 1A.~~	~~Risk Factors~~		23

~~Item 2.~~	~~Unregistered Sales of Equity Securities and Use of Proceeds~~		25

~~Item 3.~~	~~Defaults upon Senior Securities~~		25

~~Item 4.~~	~~Submissions of Matters to a Vote of Security Holders~~		25

~~Item 5.~~	~~Other Information~~		25

~~Item 6.~~	~~Exhibits~~		25

~~Signature~~			26

~~Exhibit Index~~			2724


			NIAGARA MOHAWK POWER CORPORATION
Date: August 14, 2007	By	/s/ Paul J. Bailey
		Paul J. Bailey
		Authorized Officer and Controller and Principal Accounting Officer


~~Date: February 12, 2007~~	By	~~/s/ Paul J. Bailey~~

		~~Paul J. Bailey~~ ~~Authorized Officer and Controller and~~ ~~Principal Accounting Officer~~


Exhibit
Number		Description
RR		Niagara Mohawk Current Report on Form 8-K dated August 7, 2007

*10(gg)		Service Agreement by and between National Grid USA and Cheryl A. LaFleur dated August 1, 2007

*31.1		Certification of Principal Executive Officer

*31.2		Certification of Principal Financial Officer

*32		Certifications Pursuant to 18 U.S.C.1350

										��
	Electric — Distribution
(In thousands of dollars)			Stranded Cost				Gas —		Electric —		Total
	Distribution		Recoveries		Total		Distribution		Transmission		Segments

Three Months Ended:

December 31, 2006
Operating revenue	$	689,977	$	47,662	$	737,639	$	205,631	$	60,199	$	1,003,469
Operating income before income taxes		45,409		28,908		74,317		19,722		17,907		111,946
Depreciation and amortization		34,117		28		34,145		9,866		8,764		52,775
Amortization of stranded costs and rate plan deferrals		33,999		63,984		97,983		—		746		98,729

December 31, 2005
Operating revenue	$	605,730	$	147,717	$	753,447	$	296,181	$	61,857	$	1,111,485
Operating income before income taxes		57,557		44,626		102,183		25,424		22,140		149,747
Depreciation and amortization		33,569		55		33,624		9,582		8,558		51,764
Amortization of stranded costs and rate plan deferrals		—		67,140		67,140		—		—		67,140


Nine Months Ended:

December 31, 2006
Operating revenue	$	2,049,504	$	180,489	$	2,229,993	$	479,466	$	189,059	$	2,898,518
Operating income before income taxes		186,319		106,090		292,409		41,918		67,190		401,517
Depreciation and amortization		101,616		111		101,727		29,471		26,257		157,455
Amortization of stranded costs and rate plan deferrals		101,998		191,952		293,950		—		2,238		296,188

December 31, 2005
Operating revenue	$	1,860,288	$	423,550	$	2,283,838	$	578,239	$	195,921	$	3,057,998
Operating income before income taxes		235,269		128,056		363,325		49,097		81,312		493,734
Depreciation and amortization		97,795		163		97,958		28,538		25,862		152,358
Amortization of stranded costs and rate plan deferrals		—		201,420		201,420		—		—		201,420


	Gain (Loss)									Total
	On			Additional						Accumulated
	Available-			Minimum						Other
(In thousands of dollars)	for-Sale			Pension			Cash Flow			Comprehensive
	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		408			—			—			408
Hedging activity		—			—			(27,636	)		(27,636	)
Reclassification adjustment for (gains) losses included in net income		(200	)		—			13,972			13,772

December 31, 2006 balance, net of tax	$	1,344		$	(1,199	)	$	(18,417	)	$	(18,272	)



⁽¹⁾		The fiscal year ended March 31, 2007 accumulated other comprehensive income (AOCI) balance has been adjusted by a $1.3 million reduction related to the fiscal year 2007 adoption of SFAS No. 158. In the fiscal year 2007 Annual Report on Form 10-K, the impact of this adjustment was presented as a 2007 activity and therefore was included in comprehensive income. However, it should have been reported as a direct reduction of accumulated other comprehensive income in the changes in equity accounts disclosed as an adjustment in the reporting period and excluded from comprehensive income. The March 31, 2007, AOCI balance reported in the fiscal year 2007 Annual Report on Form 10-K was properly stated.


Period Ended December 31, 2006
	Three			Nine
(In millions of dollars)	Months			Months


Cost of purchased gas	$	(87	)	$	(94	)
Delivery revenue		(4	)		(4	)
Other		—			(1	)

Total	$	(91	)	$	(99	)


*		Filed herewith