National Grid PLC — Interim / Quarterly Report 2007

Nov 14, 2007

6-K 1 b67205nge6vk.htm NATIONAL GRID PLC e6vk PAGEBREAK

SECURITIES AND EXCHANGE COMMISSION

Washington D.C. 20549

FORM 6-K

REPORT OF FOREIGN ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16 OF

THE SECURITIES EXCHANGE ACT OF 1934

Date: 14 November 2007

NATIONAL GRID plc

(Registrant’s Name)

1-3 Strand London WC2N 5EH (Registrant’s Address)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F þ Form 40-F o

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3- 2(b) under the Securities Exchange Act of 1934.

Yes o No þ

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorised.

NATIONAL GRID plc
By:	/s/ David C Forward
	David C Forward
	Assistant Secretary

Date: 14 November 2007

National Grid plc hereby furnishes to the U.S. Securities and Exchange Commission (Commission), financial statement information reported on Form 6-K for Niagara Mohawk Power Corporation (the Company), its indirect wholly owned US subsidiary. Form 6-K is being furnished to the Commission solely to comply with the requirements of Section 4.03 of a Senior Notes Indenture dated June 30, 1998 (Indenture) relating to the Company’s outstanding 7 3 / 4 % Series of Senior Notes (Senior Notes), which are described in Part II, Item 8. Financial Statements and Supplementary Data — Note E — Long-term debt in the Company’s annual report on Form 10-K for the fiscal year ended March 31, 2007. Form 6-K will cease immediately upon the repayment of the Senior Notes on October 1, 2008.

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NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Condensed Consolidated Statements of Operations (In thousands of dollars) (UNAUDITED)

	Three Months Ended
	September 30,			September 30,
	2007	2006		2007		2006
Operating revenues:
Electric	$ 881,283	$	889,337	$	1,664,819	$	1,621,214
Gas	80,220		90,529		285,749		273,835
Total operating revenues	961,503		979,866		1,950,568		1,895,049
Operating expenses:
Purchased electricity	345,577		380,559		682,002		687,770
Purchased gas	32,408		43,689		167,740		158,218
Other operation and maintenance	218,829		169,068		410,377		346,133
Depreciation and amortization	54,131		52,443		108,124		104,680
Amortization of stranded costs and rate plan
deferrals	120,732		98,730		241,465		197,459
Other taxes	54,158		54,631		109,783		111,218
Income taxes	32,445		45,172		46,736		69,735
Total operating expenses	858,280		844,292		1,766,227		1,675,213
Operating income	103,223		135,574		184,341		219,836
Other deductions, net	(1,167	)	(2,253	)	(2,219	)	(3,822	)
Operating and other income	102,056		133,321		182,122		216,014
Interest:
Interest on long-term debt	20,583		24,720		43,248		52,049
Interest on debt to associated companies	20,026		21,662		38,940		43,018
Other interest	14,526		4,715		21,922		9,754
Total interest expense	55,135		51,097		104,110		104,821
Net income	46,921		82,224		78,012		111,193
Dividends on preferred stock	406		406		812		812
Income available to common shareholder	$ 46,515	$	81,818	$	77,200	$	110,381

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

	Three Months Ended
	September 30,			September 30,
	2007	2006		2007		2006
Net income	$ 46,921	$	82,224	$	78,012	$	111,193
Other comprehensive income (loss), net of taxes:
Unrealized gains on securities	137		492		488		221
Hedging activity	(8,096	)	(18,040	)	(18,542	)	(23,383	)
Amortization of unrealized post-retirement benefit
costs	58		—		70		—
Reclassification adjustment for (gains) losses
included in net income	1,635		(26	)	5,922		1,568
Total other comprehensive loss	(6,266	)	(17,574	)	(12,062	)	(21,594	)
Comprehensive income	$ 40,655	$	64,650	$	65,950	$	89,599

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
	September 30,			September 30,
	2007	2006		2007		2006
Retained earnings at beginning of period	$ 998,980	$	817,300	$	976,688	$	788,737
Adoption of new accounting standard FIN 48	—		—		(8,393	)	—
Adjusted balance at beginning of period	998,980		817,300		968,295		788,737
Net income	46,921		82,224		78,012		111,193
Dividends on preferred stock	(406	)	(406	)	(812	)	(812	)
Retained earnings at end of period	$ 1,045,495	$	899,118	$	1,045,495	$	899,118

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,
	2007	2007
ASSETS
Utility plant, at original cost :
Electric plant	$ 5,958,596	$ 5,854,677
Gas plant	1,645,484	1,617,848
Common plant	292,255	288,837
Total utility plant	7,896,335	7,761,362
Less: Accumulated depreciation and amortization	2,386,260	2,318,967
Net utility plant	5,510,075	5,442,395
Goodwill	1,291,911	1,242,461
Other property and investments	50,644	47,506
Current assets:
Cash and cash equivalents	14,813	15,746
Restricted cash	81,723	37,648
Accounts receivable (less reserves of $134,612 and $126,619,
respectively, and including receivables from associated companies of
$10,729 and $10,232, respectively)	538,771	670,548
Materials and supplies, at average cost:
Gas storage	103,849	4,277
Other	25,867	27,926
Derivative instruments	—	7,945
Prepaid taxes	119,177	75,573
Current deferred income taxes	113,363	107,774
Regulatory asset — swap contracts	168,035	221,540
Other	12,321	14,595
Total current assets	1,177,919	1,183,572
Regulatory and other non-current assets:
Regulatory assets:
Merger rate plan stranded costs	2,061,291	2,220,179
Swap contracts regulatory asset	—	46,500
Regulatory tax asset	110,561	100,765
Deferred environmental remediation costs	396,597	397,407
Pension and post-retirement benefit plans	1,010,127	1,028,129
Loss on reacquired debt	48,203	51,975
Other	274,075	379,257
Total regulatory assets	3,900,854	4,224,212
Other non-current assets	26,922	26,609
Total regulatory and other non-current assets	3,927,776	4,250,821
Total assets	$ 11,958,325	$ 12,166,755

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, — 2007	2007
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stockholders’ equity:
Common stock ($1 par value)
Authorized - 250,000,000 shares
Issued and outstanding - 187,364,863 shares	$ 187,365	$	187,365
Additional paid-in capital	2,913,384		2,913,384
Accumulated other comprehensive loss	(12,120	)	(58	)
Retained earnings	1,045,495		976,688
Total common stockholders’ equity	4,134,124		4,077,379
Preferred equity:
Cumulative preferred stock ($100 par value, optionally
redeemable)
Authorized - 3,400,000 shares
Issued and outstanding - 411,715 shares	41,170		41,170
Long-term debt	1,249,300		1,249,194
Long-term debt to affiliates	1,200,000		1,200,000
Total capitalization	6,624,594		6,567,743
Current liabilities:
Accounts payable (including payables to associated
companies of $34,105 and $37,767, respectively)	319,945		330,976
Customers’ deposits	34,915		37,819
Accrued interest	50,852		56,625
Accrued taxes	2,296		30,343
Short-term debt to affiliates	512,600		395,300
Current portion of liability for swap contracts	168,035		221,540
Current portion of long-term debt	—		200,000
Derivative instruments	34,639		—
Other	69,821		105,886
Total current liabilities	1,193,103		1,378,489
Other non-current liabilities:
Accumulated deferred income taxes	1,605,042		1,694,047
Liability for swap contracts	—		46,500
Employee pension and other benefits	849,992		996,006
Liability for environmental remediation costs	396,597		397,407
Nuclear fuel disposal costs	162,169		158,196
Cost of removal regulatory liability	360,025		350,073
Deferred credits related to income taxes	160,458		—
Other	606,345		578,294
Total other non-current liabilities	4,140,628		4,220,523
Commitments and contingencies (Note C)	—		—
Total capitalization and liabilities	$ 11,958,325	$	12,166,755

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, — 2007	2006
Operating activities:
Net income	$ 78,012	$	111,193
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization	108,124		104,680
Amortization of stranded costs and rate plan deferrals	241,465		197,459
Provision for deferred income taxes	(57,746	)	54,419
Changes in operating assets and liabilities:
Net accounts receivable	131,777		151,404
Materials and supplies	(97,513	)	(81,537	)
Accounts payable and accrued expenses	(50,000	)	19,186
Accrued interest and taxes	(25,337	)	(77,546	)
Other, net	(32,840	)	(24,247	)
Net cash provided by operating activities	295,942		455,011
Investing activities:
Construction additions	(167,148	)	(145,957	)
Change in restricted cash	(44,075	)	(83,251	)
Other investments	(2,706	)	147
Other, net	566		(11,224	)
Net cash used in investing activities	(213,363	)	(240,285	)
Financing activities:
Dividends paid on preferred stock	(812	)	(812	)
Reductions in long-term debt	(200,000	)	(275,000	)
Borrowings of short-term debt to affiliates	159,500		135,900
Repayments of short-term debt to affiliates	(42,200	)	(38,300	)
Net cash used in financing activities	(83,512	)	(178,212	)
Net increase (decrease) in cash and cash equivalents	(933	)	36,514
Cash and cash equivalents, beginning of period	15,746		10,847
Cash and cash equivalents, end of period	$ 14,813	$	47,361
Supplemental disclosures of cash flow information:
Interest paid	$ 116,325	$	114,118
Income taxes paid	$ 86,153	$	88,764

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, 2007 Condensed Consolidated Balance Sheet data included in this quarterly report on Form 6-K was derived from audited financial statements included in the Company’s Annual Report on Form 10-K for the year ended March 31, 2007. The September 30, 2007 Condensed Consolidated Balance Sheet included in this Form 6-K 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, 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 six-month periods ended September 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 July 2006, the Financial Accounting Standards Board (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 for uncertain tax positions taken or expected to be taken in income tax returns. The cumulative effect of applying the provision of this interpretation 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 liabilities at fair value. This standard defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles in the United States of America (GAAP) and expands disclosures about fair value measurements. The Company is currently evaluating SFAS No. 157 and at this time cannot determine the full impact that the potential requirements may have on its financial statements.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of SFAS No. 115.” This statement permits companies to choose to measure many financial assets and 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. 159 is effective for fiscal years beginning after November 15, 2007. The Company is evaluating the impact that the adoption of SFAS No. 159 will have on its financial statements.

NOTE B — RATE AND REGULATORY ISSUES

General:

The Company’s financial statements conform to 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

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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 future payment of expenses or for return to customers) on the balance sheet. The Company’s regulatory assets were approximately $4.1 billion as of September 30, 2007 and $4.4 billion as of March 31, 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 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 MRP’s stranded regulatory assets over their planned amortization periods, assuming no unforeseen reduction in load or bypass of the CTCs. The Company’s ongoing electric business continues to be rate-regulated on a cost-of-service basis under the 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 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.

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:

As reported in the Company’s Form 10-K, the Company 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 balances as of June 30, 2005 remain subject to audit by the Department of Public Service Staff (Staff). The Stipulation also clarifies going forward procedures for recording, reporting and auditing of certain other deferrals authorized for recovery.

Third CTC reset and Deferral Account filings:

The biannual deferral account filing included in the third CTC reset was made on August 1, 2007 for deferral balances as of June 30, 2007 and projected deferrals through December 31, 2009. The deferral account recoveries proposed in the third CTC reset were approximately $136 million per year over the two year period commencing on January 1, 2008 (approximately $272 million over the two year recovery period). This represented a reduction of $64 million per year over the $200 million per year currently being collected under rates approved in the second CTC reset proceeding. The deferrals to be recovered are subject to audit by the Staff and further updates and adjustments in the proceeding. Any differences in the deferrals from this approved recovery level would be reflected in the next CTC reset that takes effect after 2009.

The Company agreed, in its comments filed in this proceeding on October 31, 2007, to adjust rates submitted in its August 1 filing to reflect a proposal by the parties in the proceeding which will accelerate the KeySpan Follow-on Merger Credit allocable to the Company’s customers. This proposal will credit customers over the next two years the net present value of the KeySpan Follow-on Merger Credit that otherwise would have been credited over the four years remaining on the term of the MRP. The amount of deferral account recovery to be reflected in the rates would be reduced from $136 million per year to $124 million per year to account for the accelerated recognition of the synergy savings in rates. A PSC order establishing the amount of deferral account cost recovery that will be reflected in the rates during 2008-09 is expected in December of this year. However, the amount of savings credited to electric customers is subject to future adjustment upon a final PSC decision on the Company’s Follow-on Merger Credit Compliance Filing and Request for Approval regarding the KeySpan synergy savings allocable to the Company and its customers submitted in this proceeding and in Case 06-M-0878 on October 22, 2007.

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Service Quality Penalties:

In connection with its MRP, 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.

The MRP includes a provision related to frequency of outages that causes the annual $4.4 million penalty associated with this standard to be doubled under certain circumstances when penalties have been incurred in the current year and two of the last four years. In calendar year 2006, the Company incurred a $4.4 million penalty related to outage frequency, which it recorded in fiscal year 2007. Similar penalties were incurred in the two prior years. Based on this performance and consistent with the terms of the MRP, the PSC on November 7, 2007 doubled the penalty associated with the frequency of outages to $8.8 million per year. In September 2007, the Commission also modified the MRP, in the context of the KeySpan merger proceeding, to add an additional incremental $4.4 million penalty exposure for each consecutive year the Company misses the target for a doubled penalty.

The Company has recorded service quality expenses of $14.5 million for the six months ended September 30, 2007.

Asset Condition and Capital Investment Plan:

On October 22, 2007, the Company filed with the PSC reports on its asset condition and capital investment plan for its electric transmission and distribution system. The Company’s plan involves significant investment in capital improvements over the projections initially included in its MRP. In the order approving the KeySpan merger, the PSC found that the rate impacts associated with incremental investments during the remaining period of the MRP would be limited to 50% of the total rate impact as ultimately determined by the PSC.

NOTE C — COMMITMENTS AND CONTINGENCIES

Environmental Contingencies:

The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations. Like many other industrial companies, the Company’s transmission and distribution 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 86 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 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. As of

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September 30, 2007 and March 31, 2007, the Company had accrued liabilities related to its environmental obligations of $397 million. The high end of the range of potential liabilities at September 30, 2007, was estimated at $519 million.

Acquisition:

In 2006, National Grid plc, the ultimate parent of the Company, announced the proposed acquisition of KeySpan Corporation (KeySpan) for $7.3 billion together with the assumption of approximately $4.5 billion of debt. This significantly expanded 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 long-term contract with the Long Island Power Authority. KeySpan’s other interests includes 6.6 GW of generation capacity, together with a small portfolio of non-regulated, energy-related services, and strategic investments in certain gas pipeline, storage and liquefied natural gas assets. Following receipt of required regulatory approvals, the acquisition was completed on August 24, 2007. The combination of its current US operations with those of KeySpan resulted in National Grid plc becoming the second largest energy utility in the US.

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 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.

(In thousands of dollars)	Electric-Distribution — Distribution	Stranded Cost Recoveries	Total	Gas- Distribution	Electric - Transmission		Total Segments
Three Months Ended:
September 30, 2007
Operating revenue	$ 738,983	$ 72,716	$ 811,699	$ 80,220	$	69,584	$ 961,503
Operating income before
income taxes	89,274	27,243	116,517	(3,044	)	22,195	135,668
Depreciation and amortization	34,943	54	34,997	10,131		9,003	54,131
Amortization of stranded costs
and rate plan deferrals	34,650	82,266	116,916	—		3,816	120,732
September 30, 2006
Operating revenue	$ 755,170	$ 66,602	$ 821,772	$ 90,882	$	67,212	$ 979,866
Operating income before
income taxes	113,102	38,218	151,320	3,661		25,765	180,746
Depreciation and amortization	33,809	29	33,838	9,811		8,794	52,443
Amortization of stranded costs
and rate plan deferrals	34,000	63,984	97,984	—		746	98,730

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	Electric-Distribution — Stranded Cost			Gas -	Electric -	Total
(In thousands of dollars)	Distribution	Recoveries	Total	Distribution	Transmission	Segments
Six Months Ended:
September 30, 2007
Operating revenue	$ 1,385,804	$ 143,498	$ 1,529,302	$ 285,749	$ 135,517	$ 1,950,568
Operating income before
income taxes	116,468	53,154	169,622	16,628	44,827	231,077
Depreciation and amortization	69,841	108	69,949	20,190	17,985	108,124
Amortization of stranded costs
and rate plan deferrals	69,300	164,532	233,832	—	7,633	241,465
September 30, 2006
Operating revenue	$ 1,358,959	$ 132,827	$ 1,491,786	$ 274,403	$ 128,860	$ 1,895,049
Operating income before
income taxes	140,910	77,182	218,092	22,196	49,283	289,571
Depreciation and amortization	67,499	83	67,582	19,605	17,493	104,680
Amortization of stranded costs
and rate plan deferrals	67,999	127,968	195,967	—	1,492	197,459

	Electric-Distribution — Stranded Cost			Gas -	Electric -		Total
(In thousands of dollars)	Distribution	Recoveries	Total	Distribution	Transmission	Corporate	Segments
September 30, 2007
Goodwill	$ 742,078	$ —	$ 742,078	$ 227,874	$ 321,959	$ —	$ 1,291,911
Total assets	5,935,659	2,098,383	8,034,042	2,089,481	1,687,269	147,533	11,958,325
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

NOTE E — CHANGES IN EQUITY ACCOUNTS

	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	488	—		—		488
Hedging activity	—	—		(18,542	)	(18,542	)
Amortization of post-retirement benefit costs	—	70		—		70
Reclassification adjustment for losses
included in net income	156	—		5,766		5,922
September 30, 2007 balance, net of tax	$ 2,100	$ (1,199	)	$ (13,021	)	$ (12,120	)

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

(In thousands of dollars)	Six Months Ended September 30, — 2007		2006
Unrealized gains on securities	$ (325	)	$ (147	)
Hedging activity	12,361		15,589
Amortization of Pension and PBOP costs	(47	)	—
Reclassification adjustment for gains included in net income	(3,948	)	(1,045	)
	$ 8,041		$ 14,397

(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.

NOTE F — EMPLOYEE BENEFITS

As discussed in the Company’s Annual Report on Form 10-K for the fiscal year ended March 31, 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-month and six-month periods ended September 30, 2007 and 2006 include the following:

(In thousands of dollars)
For the Three Months Ended	Pension Benefits			Benefits
September 30,	2007	2006		2007		2006
Service cost	$ 5,604	$	5,239	$	3,735	$	3,387
Interest cost	17,106		17,328		18,654		18,008
Expected return on plan assets	(20,077	)	(17,165	)	(10,954	)	(10,907	)
Amortization of prior service cost	791		800		3,646		3,646
Amortization of net loss	8,575		6,322		6,795		6,461
Net periodic benefit cost	$ 11,999	$	12,524	$	21,876	$	20,595
Special termination benefits	1,541		—		44		—
Total expense	$ 13,540	$	12,524	$	21,920	$	20,595

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(In thousands of dollars)
For the Six Months Ended	Pension Benefits			Benefits
September 30,	2007	2006		2007		2006
Service cost	$ 12,425	$	12,731	$	8,074	$	7,925
Interest cost	33,801		35,613		38,146		36,967
Expected return on plan assets	(38,812	)	(33,286	)	(21,977	)	(22,549	)
Amortization of prior service cost	1,600		1,619		7,293		7,293
Amortization of net loss	15,991		14,163		14,904		14,355
Net periodic benefit cost	$ 25,005	$	30,840	$	46,440	$	43,991
Special termination benefits	1,541		—		44		—
Total expense	$ 26,546	$	30,840	$	46,484	$	43,991
Estimated contributions for this year	$ 378,480			$	—

In connection with the acquisition of KeySpan, National Grid plc and KeySpan in an effort to achieve necessary reduction through voluntary means, offered 673 non-union employees voluntary early retirement offer (VERO) packages in June 2007. Of the 673 eligible employees, 549 enrolled in the VERO, including 44 of the Company’s employees. Employees enrolled in the early retirement program will retire between October 1, 2007 and September 1, 2010. The Company’s share of the cost of the VERO program is expected to be $37 million which includes VERO costs allocated from affiliates. The Company recorded $6 million of expense for the three and six month periods ended September 30, 2007 which reflects program participants that retired as of October 1, 2007.

NOTE G — INCOME TAXES

In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes,” an Interpretation of SFAS No. 109, “Accounting for Income Taxes.” 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 recorded as a deferred tax liability. The adjusting entry also included $49.5 million which was recorded to goodwill because it related to the pre-acquisition period. 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 $36.1 million, gross. During the quarter ended September 30, 2007, the Company recorded interest expense of $6.4 million, gross. However, upon adoption of FIN 48 there was no material effect on our operations, financial position or cash flows.

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 six months ended September 30, 2007.

As of September 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 thru March 31, 2005.

The IRS completed their fieldwork on the current audit during the quarter ended September 30, 2007. As a result, the Company expects to pay $2 million of the 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% from 7.5%, and the adoption of a

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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 their financial position, cash flows or results of operation.

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 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 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 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 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, 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.

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RESULTS OF OPERATIONS

EARNINGS

Net income for the three and six months ended September 30, 2007 decreased by $35 million and $33 million, respectively, compared to the same periods in the prior fiscal year. These decreases were primarily due to increased bad debt expense and increased service quality penalties. 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 costs. Rates are 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 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 electricity for customers who
purchase their power from competitive electricity suppliers. |
| • | Sales for resale — sales of excess electricity to the 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 — charges for the distribution (transportation) and the purchase of gas
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 to entities that are not
distribution system customers and not retail gas users. |

Electric revenues decreased $8 million during the three months ended September 30, 2007 compared to the same period in the prior fiscal year. The decrease was primarily due to a decrease in sales volumes of $29 million (8.0% kWh) and a decrease in the cost of electricity which was passed on to customers of $6 million. Contributing to the decrease in sales volumes was the migration of customers to competitive suppliers as well as milder weather in the three month period in this fiscal year compared to the same period in the prior fiscal year. This decrease was partially offset by an increase of $17 million from the recovery of the MRP deferral account. In fiscal 2006, the Company implemented a $100 million rate increase during the nine month period ended December 31, 2006 to recover MRP deferrals. The Company implemented a second rate increase of $100 million effective January 1, 2007 resulting in total recovery for calendar year 2007 of $200 million. Also offsetting the decrease was a $5 million increase in stranded cost revenues reflecting recovery 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. In addition, electric revenue increased by $6 million due to deferral account adjustments required by the Stipulation (see Note B — Rate and Regulatory Issues) made during this fiscal year with no comparable adjustment in the prior fiscal year.

Electric revenues increased $44 million during the six months ended September 30, 2007 compared to the same period in the prior fiscal year. The increase was primarily due to $33 million recovery of the MRP deferral account discussed

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above and an increase in the cost of electricity that was passed on to customers of $12 million offset by a decrease in sales volumes of $18 million (2.6% kWh). Also contributing to the increase was an $11 million increase in stranded cost revenues reflecting recovery that will continue to occur unevenly at levels that increase over the ten-year term of the plan ending on December 31, 2011. In addition, electric revenue increased by $6 million due to deferral account adjustments required by the Stipulation (see Note B — Rate and Regulatory Issues) made during this fiscal year with no comparable adjustment in the prior fiscal year. The sales volume decrease was primarily a result of the migration of customers to competitive suppliers.

Gas revenues decreased by $10 million for the three months ended September 30, 2007 and increased by $11 million for the six months ended September 30, 2007, compared to the same periods in the prior fiscal year. The decrease for the three months ended September 30, 2007 was due to lower gas prices passed through to customers, a decrease in weather normalized use per customer of residential and small commercial customers, offset by an increase in revenues related to the Medicare Tax Act Benefit, New England Gas Synergy Savings and Bonus Depreciation. The increase for the six months ended September 30, 2007 was due to increased volume of gas passed through to customers related to colder weather, an increase in the average number of customers for the residential customers affecting delivery service margins and an increase in revenues related to the Medicare Tax Act Benefit, New England Gas Synergy Savings and Bonus Depreciation. The table below details the components of the fluctuations:

Change in Gas Revenues Periods Ended September 30, 2007

(In millions of dollars)	Three — Months		Six — Months
Cost of purchased gas	$ (11	)	$ 9
Delivery revenue	1		2
Total	$ (10	)	$ 11

The volume of gas sold for the three months ended September 30, 2007, excluding transportation of customer-owned gas, was approximately 6.8% lower than the volume in the prior fiscal year. Usage for the three months ended September 30, 2007, adjusted for normal weather, was also approximately 6.8% lower than the volume in the prior fiscal year.

The volume of gas sold for the six months ended September 30, 2007, excluding transportation of customer-owned gas, increased 1.2 million Dth, or 8.5%, compared to the same period in the prior fiscal year. The increase for the six months ended September 30, 2007 is due to colder than normal weather compared to the same period in prior fiscal year. Usage for the six months ended September 30, 2007, adjusted for normal weather, decreased 0.09 million Dth, or 0.6%.

OPERATING EXPENSES

Purchased electricity decreased by $35 million and $6 million during the three and six months ended September 30, 2007 compared to the same periods in the prior fiscal year. Of the $35 million decrease in purchased electricity for the three month period, approximately $29 million of the decrease was contributed by decreased volume and approximately $6 million was contributed by decreased price of power. The decrease in the volume of electricity purchased of 0.5 billion kWh, or 8.0% was primarily caused by the migration of customers to competitive suppliers as well as milder weather in the current fiscal year compared to the same period in the prior fiscal year. Of the $6 million decrease in purchased electricity for the six month period, approximately $18 million of the decrease was contributed by decreased volume that was partially offset by an increase of $12 million related to the price of power. The decrease in the volume of electricity purchased of 0.3 billion kWh, or 2.6% was primarily caused by the migration of customers to competitive suppliers. Decreased purchased electricity costs do not affect electric margin or net income because the Company’s rate plan allows full recovery from customers.

Purchased gas expense decreased $11 million for the three months ended September 30, 2007 and increased $9 million for the six months ended September 30, 2007, compared to the same periods in the prior fiscal year. Contributing to the decrease of $11 million in the three months ended September 30, 2007 is a decrease in gas prices of $2 million, a decrease

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in gas volumes sold of $3 million and a decrease of $6 million related to gas purchased for off-system sales. Contributing to the increase of $9 million for the six months ended September 30, 2007 was an increase of $9 million in gas volumes to system customers and an increase of $2 million related to gas purchased for off-system sales, offset by a decrease of $2 million in gas commodity prices. These costs do not affect gas margin because the Company’s rate plan allows full recovery from customers.

Other operation and maintenance expense increased $50 million and $64 million for the three and six months ended September 30, 2007 compared to the same periods in the prior fiscal year. The table below details the components of the fluctuations.

Periods Ended September 30, 2007	Three	Six
(In millions of dollars)	Months	Months
VERO	$ 6	$ 6
Bad debt expense	14	17
Service quality penalties	12	12
Consultants and contractors	9	12
Energy management assessments	1	4
Storm costs	2	7
Other	6	6
Total	$ 50	$ 64

In connection with the acquisition of KeySpan, National Grid plc and KeySpan in an effort to achieve necessary reduction through voluntary means, offered 673 non-union employees VERO packages in June 2007. Of the 673 eligible employees, 549 enrolled in the VERO, including 44 of the Company’s employees. Employees enrolled in the early retirement program will retire between October 1, 2007 and September 1, 2010. The Company’s share of the cost of the VERO program is expected to be $37 million which includes VERO costs allocated from affiliates. The Company recorded $6 million of expense for the three and six month periods ended September 30, 2007 which reflects program participants that retired as of October 1, 2007.

Bad debt expense increased for the three and six month periods due to reserve changes driven by higher levels of older aged receivables.

Service quality penalties have increased due to the accrual of potential penalties associated with failing to achieve electric reliability measures. Service quality penalties are described in Note B — Rate and Regulatory Issues.

Consultants and contractors costs increased primarily due to increased tree trimming costs associated with the Company’s reliability improvement program. In addition, the Company has been utilizing external vendors due to merger integration initiatives.

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 result in an offsetting adjustment to revenues.

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 specific 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 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 fiscal year that did not qualify for recovery from customers.

Amortization of stranded costs and rate plan deferrals increased $22 million and $44 million during the three and six months ended September 30, 2007 compared to the same periods in the prior fiscal year. These increases are primarily due to increased MRP deferral recoveries of $17 million and $33 million for the three and six months ended September 30, 2007, respectively, and stranded cost revenues as described in the electric revenue section of $5 million and $11 million for the three and six months ended September 30, 2007, respectively. Under the MRP, the stranded cost

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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 account balance is included in the Company’s revenues and does not impact net income.

Income taxes decreased $13 million and $23 million for the three and six months ended September 30, 2007 compared to the same periods in the prior fiscal year. The decreases were primarily due to lower book pretax income.

NON-OPERATING EXPENSES

Interest charges increased $4 million for the three months ended September 30, 2007 compared to the same period in the prior fiscal year. Interest charges remained relatively unchanged for the six months ended September 30, 2007 compared to the same period in the prior fiscal year. Other interest increased due to the adoption of FIN 48 during fiscal 2008 (see Note G-Income Taxes) and interest associated with a recent order from the FERC related to certain transmission interconnection contracts. This was partially offset by interest on long-term debt which decreased for the three and six months ended September 30, 2007 due to long-term debt maturities during fiscal 2007.

LIQUIDITY AND CAPITAL RESOURCES

Short-term liquidity:

At September 30, 2007, the Company’s principal sources of liquidity included cash and cash equivalents of $15 million and accounts receivable of $539 million. The Company has a negative working capital balance of $15 million primarily due to short-term debt due to affiliates of $513 million and accounts payable of $320 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 were $296 million for the six months ended September 30, 2007.

The primary activities affecting operating cash flows are:

•	depreciation and amortization of $108 million.
•	amortization of stranded costs and rate plan deferrals of $241 million in accordance with
the MRP.
•	decrease in accounts receivable of $132 million.

These increases were partially offset by:

| • | increase in materials and supplies of $98 million primarily due to a higher level of gas
storage. |
| --- | --- |
| • | decrease in accrued interest and taxes of $25 million, primarily due to the timing of the
municipal taxes due to the State of New York. |

Net cash used in investing activities was $213 million for the six months ended September 30, 2007 compared to $240 million during the same period in the prior fiscal year. This was primarily a result of restricted cash of $44 million at September 30, 2007 compared to $83 million at September 30, 2006 partially offset by increases in construction additions of $167 million at September 30, 2007 compared to $146 million at September 30, 2006.

Net cash used in financing activities was $84 million for the six months ended September 30, 2007 compared with $178 million during the same period in the prior fiscal year. The decrease was primarily due to lower debt repayment of $200 million at September 30, 2007 compared to $275 million at September 30, 2006. This was partially offset by increased borrowings of short-term debt from affiliates of $117 million at September 30, 2007 compared to $98 million at September 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, 2007, Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Liquidity and Capital Resources” for further information on long-term commitments.

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