UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended March 31, 2006

OR

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

For the transition period                                          to                                            

Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address and Telephone Number	Identification Number
1-2987	Niagara Mohawk Power Corporation	15-0265555
	(a New York corporation)
	300 Erie Boulevard West
	Syracuse, New York 13202
	315.474.1511

Securities registered pursuant to Section 12(b) of the Act:
(Each class is registered on the New York Stock Exchange)

Registrant	Title and Class
Niagara Mohawk Power Corporation	Preferred Stock ($100 par value-cumulative):
	3.90% Series
	3.60% Series

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
YES o      NO þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
YES o      NO þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES þ      NO o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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

Large accelerated filer o           Accelerated filer o           Non-accelerated filer þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
YES o      NO þ
State the aggregate market value of the common equity held by non-affiliates of the registrant: N/A

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

Registrant	Title		Shares Outstanding at June 20, 2006
Niagara Mohawk Power Corporation	Common Stock, $1.00 par value		187,364,863
		(all held by Niagara Mohawk Holdings, Inc.)

NIAGARA MOHAWK POWER CORPORATION

TABLE OF CONTENTS

		PAGE
	PART I
Item 1.	Business		4
Item 1A.	Risk Factors		6
Item 1B.	Unresolved Staff Comments		8
Item 2.	Properties		8
Item 3.	Legal Proceedings		9
Item 4.	Submission of Matters to a Vote of Security Holders		9
	PART II
Item 5.	Market for the Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchases of Equity Securities		9
Item 6.	Selected Consolidated Financial Data		9
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		10
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		20
Item 8.	Financial Statements and Supplementary Data		24
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		59
Item 9A.	Controls and Procedures		59
Item 9B.	Other Information		59
	PART III
Item 10.	Directors and Executive Officers of the Registrant		60
Item 11.	Executive Compensation		62
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		67
Item 13.	Certain Relationships and Related Transactions		68
Item 14.	Principal Accountant Fees and Services		68
	PART IV
Item 15.	Exhibits and Financial Statement Schedules		69
Signatures			71

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Cautionary Statement

This Annual Report on Form 10-K of Niagara Mohawk Power Corporation (the Company) 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. 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 Regulations”, as amended, and the Merger Rate Plan 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, 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.

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NIAGARA MOHAWK POWER CORPORATION

PART I

ITEM 1. BUSINESS

Niagara Mohawk Power Corporation (the Company) was organized in 1937 under the laws of New York State and is engaged principally in the regulated energy delivery business in New York State. The Company provides electric service to approximately 1,600,000 electric customers in the areas of eastern, central, northern and western New York and sells, distributes, and transports natural gas to approximately 569,000 gas customers in areas of central, northern and eastern New York.

Niagara Mohawk Holdings, Inc. (Holdings), the parent company of the Company, is a wholly owned subsidiary of National Grid USA (National Grid). National Grid is a wholly owned subsidiary of National Grid plc (formerly known as National Grid Transco plc).

Regulation and Rates: In conjunction with the closing of the merger with National Grid, a new rate plan (the Merger Rate Plan) that had been approved by the PSC went into effect, superseding the prior rate plan. Since then, several critical initiatives have been undertaken by various regulatory bodies and the Company that have had, and are likely to continue to have, a significant impact on the Company and the utility industry.

Merger Rate Plan: The Company’s delivery rates are governed by a ten-year rate plan that began on February 1, 2002. Under the plan, after reflecting the Company’s share of savings related to the acquisition, it may earn a threshold return on equity for the electricity distribution business of 10.6%, up to 11.75% without any sharing with customers (12.0% if certain customer outreach, education, competition-related and low income incentive targets are met). Half of any amounts in excess of 12%, up to 14%, 25% of any earnings in excess of that up to 16% and 10% beyond that are retained by the Company. This effectively offers the Company the potential to achieve a return on equity in excess of the regulatory allowed return of 10.6%. The return on equity is calculated cumulatively from inception to December 31, 2005 and annually thereafter for the prior two calendar years. The earnings calculation used to determine the regulated returns excludes half of the synergy savings, net of the cost to achieve them, that were assumed in the rate plan based on the Company’s merger with National Grid. Under the plan, gas delivery rates were frozen until the end of the 2004 calendar year, after which the Company has the right to request an increase at any time, if needed. The Company may earn a threshold return on equity ranging from 10.6% to 12.6% depending on the achievement of certain customer migration levels and customer awareness and understanding of gas competitive opportunities. Above this threshold, the revenue equivalent of gas earnings must be shared equally between shareholders and customers. The Company collects the transmission business revenues under several Federal Energy Regulatory Commission (FERC) rate schedules and the state energy delivery rates discussed above. Total transmission business revenues are determined by the state-approved 10-year rate plan.

The Company resets its Competitive Transition Charges (CTC) in electricity rates every two years under its Merger Rate Plan (the Plan). The CTC reset is intended to account for changes in forecasted electricity and natural gas commodity prices, and the effects those changes have on the Company’s above-market payments under legacy power contracts that otherwise would be stranded. In addition, the Merger Rate Plan allows the Company to recover amounts exceeding $100 million in its deferral accounts (as projected through the end of each two-year CTC reset period). In accordance with the Merger Rate Plan, deferral accounts were established to track changes in specified cost and revenue items that have occurred since the Plan was established. These changes include costs or revenues related to changes in tax, accounting, and regulatory requirements, changes

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from the levels of pension and post-retirement benefit expenses from the levels specified in the Plan, and various other items, including storms, environmental remediation costs, and various rate discounts. On July 29, 2005, the Company filed its bi-annual CTC reset and deferral account recovery filing to reset rates charged to customers beginning January 1, 2006. In the July 29, 2005 filing, the Company included a proposal to recover the excess balance of the deferral accounts as of June 30, 2005 of $196 million and a projection through the end of the two year period of $373 million. 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 actual deferral-related surcharge began in April 2006 and the full $100 million will be collected over the last nine months of the 2006 calendar year. An audit of the deferral amount by the Department of Public Service Staff (DPS Staff) is ongoing. A formal hearing process has been established before a hearing officer at the PSC to litigate the levels in the deferral account. Under the hearing schedule, the Staff will be filing testimony setting forth its initial adjustments in early August. The Company will continue to defer costs and revenues, as applicable, through the end of the Merger Rate Plan on December 31, 2011. The Company’s future filings for recovery of deferred amounts are subject to regulatory review and approval.

Electric Supply: Although the Company has exited the generation business, the Company must still arrange for electric supply through a transition period and as provider of last resort. As such the Company will provide electricity to its customers who are unable or unwilling to obtain an alternative supplier which accounts for approximately 92% of the Company’s customers and 59% of its deliveries. The Company purchases energy from various suppliers under long-term Purchase Power Agreements (PPAs) and purchases any additional power needs on the open market through the New York Independent System Operator (NYISO). The Company also enters into financial swaps in order to hedge the price of electricity. For a discussion of the results of the power contracts and several financial agreements to hedge the price of electricity, see Part II, Item 8. Financial Statements and Supplementary Data — Note D – Commitments and Contingencies and Note L – Derivatives and Hedging Activities.

Electric Delivery: As of March 31, 2006, the Company had approximately 52,000 pole miles of transmission and distribution lines for electricity delivery. Evaluation of these facilities relative to the requirements of the New York State Reliability Council, Northeast Power Coordinating Council, North American Electric Reliability Council, NYISO and PSC, their orders, operating and planning guides and criteria, security considerations, and anticipated Company internal and external electrical demands is an ongoing process intended to maintain the reliability of electric service. The Company continually reviews the adequacy of its electric delivery facilities and establishes capital requirements to support (within the above processes) its asset renewal, existing load and new load growth needs.

Gas Supply: The majority of the Company’s gas sales are for residential and commercial space heating. The Company purchases its natural gas under firm supply agreements. The natural gas purchased may be either transported or stored for later transport on a firm basis through interstate storage facilities and pipelines to the Company’s system.

Gas Delivery: The Company sells, distributes and transports natural gas to a geographic territory that generally extends from Syracuse to Albany. The northern reaches of the system extend to Watertown and Glens Falls. Not all of the Company’s distribution areas are physically interconnected with one another by its own facilities. The gas distribution system is served by 3 interstate natural gas pipelines regulated by the FERC and one intrastate pipeline regulated by the PSC. The Company has nineteen direct connections with Dominion Transmission, Inc., two with Iroquois Gas Transmission, one with Tennessee Gas Pipeline and one with Empire State Pipeline (intrastate).

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Compliance with Environmental Requirements: The Company’s operations and facilities are subject to numerous federal, state and local laws and regulations relating to the environment including, among other things, requirements concerning air and water quality; wetlands and flood plains; storage, transportation and disposal of hazardous wastes and substances; storage tanks; and site remediation. The Company believes it is handling identified wastes and by-products in a manner consistent with applicable requirements. The environmental management systems for the Company’s distribution, transmission and investment recovery facilities are certified to the International Organization for Standardization (ISO) 14001 standard. Management believes it is probable that costs associated with environmental compliance will continue to be recovered through the ratemaking process. The Company’s compliance has no material effect on its capital expenditures, earnings or competitive position. For a discussion of the Company’s reserves for environmental liabilities and its ability to recover these types of expenditures in rates, see Part II, Item 8. Financial Statements and Supplementary Data – Note B — Rate and Regulatory Issues.

The Company has implemented an environmental audit program to identify any potential areas of concern and aid in compliance with legal requirements. The Company is also currently conducting a program to investigate and remediate, as necessary to meet current environmental standards, certain properties associated with former gas manufacturing and other properties which the Company has learned may be contaminated with industrial waste, as well as investigating identified industrial waste sites as to which it may be determined that the Company has contributed. The Company has also been advised that various federal, state or local agencies believe certain properties require investigation and has prioritized the sites based on available information in order to enhance the management of investigation and remediation, if necessary.

Employee Relations: The Company’s work force at March 31, 2006 numbered approximately 4,300 employees, of whom approximately 82% were union members. The Company also receives substantial support for its activities from employees of National Grid USA Service Company, Inc., an affiliate that provides administrative services support to all National Grid companies. The Company reimburses the Service Company for the costs associated with those services.

The Company believes relations with employees are good.

Seasonality: There is seasonal variation in electric customer load, usually peaking in the winter and summer months. The seasonality is correlated with the colder or warmer temperature because more electricity is used for heating or cooling during those months.

There is a seasonal variation in gas customer sales, with loads usually peaking in the winter months. The seasonality is correlated with colder temperatures when more gas is used for heating.

Also see Part II, Item 8. Financial Statements and Supplementary Data — Note O- Quarterly Financial Data (unaudited).

ITEM 1A. RISK FACTORS

This Annual Report on Form 10-K 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

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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 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% of annual gas earnings.

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.

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

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

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

There are no unresolved SEC staff comments required to be reported under this Item 1B.

ITEM 2. PROPERTIES

Electric Transmission and Distribution: As of March 31, 2006, the Company’s electric transmission and distribution systems were composed of:

• 717 substations with a rated transformer capacity of approximately 23,090,000 kilo-volt-amperes;

• approximately 9,400 pole miles of overhead and underground transmission lines;

• approximately 36,000 conductor primary structure miles of overhead distribution lines; and

• about 6,500 cable primary structure miles of underground distribution cables.

A portion of the Company’s transmission and distribution lines are located on property owned by the Company. With respect to the Company’s transmission and distribution lines that are located on property not owned by the Company, the Company’s practice is to obtain right of way agreements.

The electric system of the Company is directly interconnected with other electric utility systems in New York, Massachusetts, Vermont, Pennsylvania and the Canadian provinces of Ontario and Quebec, and indirectly interconnected with most of the electric utility systems through the Eastern Interconnection of the United States and Canada.

Gas Distribution: The Company distributes gas that it purchases from suppliers and transports gas owned by others. As of March 31, 2006, the Company’s natural gas delivery system was comprised of approximately 8,600 miles of pipelines. Only a small part of these natural gas pipelines and mains are located on property owned by the Company. With respect to natural gas pipelines and mains that are not located on property owned by the Company, the Company’s practice is to obtain right of way agreements.

Native American Matters: The Company’s facilities are potentially affected by land claim litigation involving the Oneida, Mohawk and Onondaga Nations. Other than the Cayuga Nation’s and Seneca land claims, which have been dismissed by the courts, the land claim litigation has not been resolved. The Company continues to monitor the land claim litigation and, where necessary, defend its interests.

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Mortgage Liens: Substantially all of the Company’s operating properties are subject to mortgage liens securing its mortgage debt.

ITEM 3. LEGAL PROCEEDINGS
None.

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

No matters were submitted to a vote of security holders during the last quarter of the fiscal year ended March 31, 2006. On May 3, 2006, by unanimous written consent of the sole common stockholder,

o The following persons were elected as directors: William F. Edwards, Barbara A. Hassan, Michael E. Jesanis, Michael J. Kelleher, Cheryl A. LaFleur, Clement E. Nadeau, and Anthony C. Pini.

o PricewaterhouseCoopers LLP was appointed the Company’s independent registered public accounting firm for the fiscal year ending March 31, 2007.

PART II

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The common stock of the Company is held solely by Niagara Mohawk Holdings, Inc., and therefore indirectly by National Grid and National Grid plc. There is no public trading market for the Company’s common stock. The Company did not purchase any of its equity securities during the fourth quarter of fiscal 2006. For information about the Company’s payment of dividends and restrictions on those payments, see Item 6. Selected Consolidated Financial Data and Item 8. Financial Statements and Supplementary Data.

ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA

At the time of the merger with National Grid, the Company changed its fiscal year from a calendar year ending December 31 to a fiscal year ending March 31. The Company made this change in order to align its fiscal year with that of its parent company, National Grid. The Company’s first new full fiscal year began on April 1, 2002 and ended on March 31, 2003.

The following tables set forth selected financial information for the Company for the years ended March 31, 2006, 2005, 2004, 2003, the sixty day period ended March 31, 2002, the thirty day period ended January 30, 2002, the three months ended March 31, 2001, and the year ended December 31, 2001. These tables have been derived from the financial statements of the Company and should be read in connection therewith.

On January 31, 2002, the Company was acquired by National Grid in a purchase business combination recorded under the “push-down” method of accounting, resulting in a new basis of accounting for the “successor” period beginning January 31, 2002. Information relating to all “predecessor” periods prior to the acquisition is presented using the Company’s historical basis of accounting. The following selected financial data for the Company may not be indicative of the Company’s future financial condition, results of operations or cash flows.

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													60 Day			30 Day			Three
													Period			Period			months
	Year Ended			Year Ended			Year Ended			Year Ended			Ended			Ended			Ended			Year Ended
	March 31,			March 31,			March 31,			March 31,			March 31,			January 30,			March 31,			December 31,
(in 000’s except	2006			2005			2004			2003			2002			2002			2001			2001
per share data)	(Successor)			(Successor)			(Successor)			(Successor)			(Successor)			(Predecessor)			(Predecessor)			(Predecessor)
Operating revenues	$	4,344,023		$	3,925,171		$	4,063,617		$	4,019,450		$	689,705		$	362,622		$	1,179,706		$	4,114,713
Net income (loss)		317,076			263,249			139,690			125,871			30,646			(20,941	)		34,010			19,358
Income (loss) from continuing operations per average common share			*			*			*			*			*			*			*			*
Total assets		12,280,968			12,518,362			12,618,659			12,549,865			12,101,588				**		12,037,039			11,436,554
Long-term debt		2,648,934			2,923,569			3,473,467			3,953,989			4,146,642				**		4,674,004			4,419,822
Mandatorily redeemable preferred stock		—			—			—			—			—				**		53,750			50,700
Dividends paid per common share			*			*			*			*			*			*			*			*

*	As all of the Company’s shares of common stock are owned by its parent company, dividend information and per share data are not relevant.
**	Balance Sheet information as of the 30 day period ended January 30, 2002 is not provided.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to apply policies and make estimates and assumptions that affect the results of operations and the reported amounts of assets and liabilities in the financial statements. Because of the inherent uncertainty in the nature of the matters where estimates are used, actual amounts could differ from estimated amounts. The following accounting policies represent those that management believes are particularly important to the financial statements and require the use of judgment in estimating matters that are inherently uncertain.

Regulatory Assets and Liabilities: Regulatory assets represent costs that have been deferred to future periods when it is probable that the regulator (namely, the FERC, PSC, or other regulatory body with jurisdiction) will allow future recovery of those costs through rates. The Company bases its assessment of recovery by either

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specific recovery measures (such as current rate agreements with the PSC) or historical precedents established by the regulatory body. Regulatory liabilities represent previous collections from customers to fund future expected costs or amounts received in rates that are expected to be refunded to customers in future periods. These regulatory assets and liabilities typically include deferral of under recovered or over recovered energy costs, environmental restoration costs and post retirement benefit costs, as well as the normalization of income taxes, and the deferral of losses incurred on debt retirements. The accounting for these regulatory assets and liabilities is in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.”

The Company continually assesses if its regulatory assets continue to meet the criteria for probability of future recovery. This assessment considers factors such as changes in the regulatory environment, recent rate orders to other regulated entities under the same jurisdiction, and the status of any pending or potential deregulation legislation. If future recovery of costs becomes no longer probable, the regulatory assets and liabilities would be recognized as current-period revenues or expenses.

Amortization of regulatory assets is provided over the recovery period as allowed in the related regulatory agreement. Under the Merger Rate Plan, a regulatory asset, called stranded costs, was established that included the costs of the Master Restructuring Agreement (MRA), the cost of any additional Independent Power Producer (IPP) contract buyouts and the deferred loss on the sale of the Company’s generation assets. The MRA represents the cost to terminate, restate or amend IPP contracts. The Company is also permitted to defer and amortize the cost of any additional IPP contract buyouts. Beginning February 1, 2002, the Merger Rate Plan stranded costs regulatory asset is being amortized unevenly over ten years with larger amounts being amortized in the latter years, consistent with projected recovery through rates. Amortization of the stranded cost regulatory asset is shown separately because it is the largest component of regulatory assets. Amortization of other regulatory assets are included in depreciation and amortization, purchased electricity & gas, and other operation and maintenance expense captions on the income statement depending on the origin of the regulatory asset.

Revenues: The Company bills its customers on a monthly cycle basis at approved tariffs based on energy delivered and a minimum customer service charge. Revenues are determined based on these bills plus an estimate for unbilled energy (discussed below) delivered between the cycle billing date and the end of the accounting period.

Unbilled Revenues: Revenues from the sale of electricity and gas to customers are generally recorded when electricity and gas are delivered to those customers. The quantity of those sales is measured by customers’ meters. Meters are read on a systematic basis throughout the month based on established meter-reading schedules. Consequently, at the end of any month, there exists a quantity of electricity and gas that has been delivered to customers but has not been captured by the meter readings. As a result, management must estimate revenue related to electricity and gas delivered to customers between their meter read dates and the end of the period.

Pension and Other Post-retirement Benefit Plans: The Company maintains qualified and nonqualified pension plans. The Company also provides health care and life insurance benefits for its retired employees. The Company’s pensions are funded through an outside trust.

Several assumptions affect the pension and other post-retirement benefit expense and the measurement of these benefit obligations. The more significant assumptions include the return on assets, discount rate, and in the case of retiree healthcare benefits, medical trends. All ongoing costs of qualified pension and post-retirement healthcare benefits plans are recoverable from customers through reconciling provisions of the Merger Rate Plan. Special termination benefits paid in connection with employee separation programs and settlement and

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curtailment losses of pension and post-retirement benefit plans when incurred are only recoverable upon approval by the PSC.

The major assumptions are:

• Return on assets. The assumed rate of return for various passive asset classes is based on both analysis of historical rates of return and forward looking analysis of risk premiums and yields. Current market conditions, such as inflation and interest rates, are evaluated in connection with the setting of long-term assumptions. A small premium is added for active management of both equity and fixed income. The rates of return for each asset class are then weighted in accordance with the target asset allocation, and the resulting long-term return on asset rate is then applied to the market-related value of assets. For fiscal 2006, the Company used an 8% assumed return on assets for its pension plan and a weighted average of 8% assumed return on assets for its other post-retirement benefits plans.

• Discount rate. The Company bases its discount rate on two measures of rates specific to the yield curve applicable to the liabilities of the plans. The actuary calculates the present value of the projected cash flows of the plans utilizing derived zero coupon interest rates specific to the timing of each respective cash flow and calculates the single weighted average interest rate that equates the total present value with the stream of future cash flows. This results in a weighted average interest rate of 5.87% based on the Citigroup Pension Discount Curve, which is based on AA-rated corporate bonds, and an interest rate of 6.16% based on a yield curve of top quartile yielding Aa corporate bonds. A discount rate of 6%, the average between the two rates, was deemed appropriate for the plans.

• Medical trends. The health care cost trend rate is the assumed rate of increase in per-capita health care charges. In fiscal year 2006, the health care cost trend assumption was updated to include rates for the pre 65 and post 65 age groups. For 2006, the initial health trend was assumed to be 10% for the pre 65 age group and 11% for the post 65 age group. The ultimate trend of 5%, for both age groups, was assumed to be reached in 2011 for the pre 65 age group and 2012 for the post 65 age group.

Goodwill: The Company applies the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” In accordance with SFAS No. 142, goodwill must be reviewed for impairment at least annually and when events or circumstances indicate that the asset may be impaired. The Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the performance of the annual goodwill impairment test. The result of the annual analysis determined that no adjustment to the goodwill carrying value was required. As a result of a settled IRS audit of pre-merger years, the Company recorded a $9 million adjustment to goodwill related to a pre-merger tax contingency.

Tax Provision: The Company’s income tax provisions, including both current and deferred components, are based on estimates, assumptions, calculations, and interpretation of tax statutes for the current and future years in accordance with SFAS No. 109, “Accounting for Income Taxes.” Determination of current year federal and state income tax will not be settled until final approval of returns by taxing authorities.

Management regularly makes assessments of tax return outcomes relative to financial statement tax provisions and adjusts the tax provisions in the period when facts become final.

Accounting for Derivative Instruments: The Company accounts for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities,” and SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” as amended. Under the provisions of SFAS No. 133, all derivatives except those qualifying for the normal purchase normal sale exception are recognized on the balance sheet at their fair value. Fair value is determined using current quoted market prices. If a

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contract is designated as a cash flow hedge, the change in its market value is generally deferred as a component of other comprehensive income until the transaction it is hedging is completed. Conversely, the change in the market value of a derivative not designated as a cash flow hedge is deferred as a regulatory asset or liability because the Company has received approval from the PSC to establish a regulatory asset or liability for derivative instruments that did not qualify for hedge accounting and were the result of regulatory rulings. A cash flow hedge is a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. To qualify as a cash flow hedge, the fair value changes in the derivative must be expected to offset 80% to 120% of the changes in fair value or cash flows of the hedged item.

RESULTS OF OPERATIONS

The following discussion and analysis highlights items that significantly affected the Company’s operations during the fiscal years ended March 31, 2006 and 2005.

EARNINGS

Net income for the fiscal year ended March 31, 2006 increased by approximately $54 million over the prior fiscal year. This increase is primarily due to higher electric and gas margin of $48 million which is mostly attributable to favorable electric volume in delivery-only sales, reduced interest costs of approximately $21 million and a positive adjustment to electric revenues of $32 million stemming from the recognition of a regulatory asset reflecting our ability to recover a previously fully reserved account receivable. These were offset by increased income tax expense of $19 million, increased depreciation expense of $3 million, increased operating and maintenance expense of $9 million and increased other deductions of $16 million. See the following discussions of revenues and operating expenses for more detailed explanations.

Net income for the year ended March 31, 2005 increased by approximately $124 million over the prior fiscal year. This increase is primarily due to decreased retiree benefit expense of $54 million relating to one-time items, a decrease in bad debt expense of $19 million, and reduced interest costs of approximately $47 million. See the following discussions of revenues and operating expenses for more detailed explanations.

REVENUES

Electric revenues increased $190 million during the year ended March 31, 2006 from the prior fiscal year. Electric revenues decreased $167 million in the twelve months ended March 31, 2005 relative to the prior fiscal year. See the table below for the contributing factors.

Change in Electric Revenue for the fiscal year ended
(in millions of dollars)	March 31, 2006			March 31, 2005
Retail sales	$	52		$	(98	)
Delivery only sales and miscellaneous revenue		185			20
Sales for resale		(47	)		(89	)
Total	$	190		$	(167	)

Retail sales include distribution delivery charges and recovery of purchased power costs from customers who purchase their electric supply from the Company. Delivery only sales are charges for only the delivery of energy for customers who purchase their power from competitive electricity suppliers. The Company recovers all costs incurred to procure power for customers that do not receive power from competitive suppliers.

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The increase in retail sales, for the fiscal year ended March 31, 2006 is primarily due to the higher cost of electricity purchased which is being passed through to customers. The increase in delivery only sales is primarily due to the migration of retail electric customers to competitive suppliers for their commodity requirements which has been occurring since the start of electricity deregulation in the state of New York. The migration of customers is also a contributing factor to the decrease in retail kilowatt-hour (kWh) sales (see table below) in the fiscal years ended March 31, 2006 and 2005. Another contributing factor to the increase in revenue was a $32 million positive adjustment to electric revenues stemming from the recognition of a regulatory asset reflecting our ability to recover a previously fully reserved account receivable. Warmer summer and colder autumn weather than experienced in the previous fiscal year also contributed to the increase in revenue for the fiscal year ended March 31, 2006.

The migration of retail electric customers to competitive suppliers was a contributing factor for the decrease in retail sales revenues in the fiscal year ended March 31, 2005 partially offset by increases in the price of electricity that was passed on to customers.

Sales for resale represent sales of electricity to the NYISO at the market price of electricity. All electricity purchased under certain purchased power contracts is sold to the NYISO. The decreases in sales to the NYISO for the years ended March 31, 2006 and March 31, 2005 were due to the expiration of some of these contracts.

Electric kilowatt-hour sales were approximately 35.8 billion and 36.6 billion for the fiscal years ended March 31, 2006 and 2005, respectively. The table below details components of the 0.8 and 1.9 billion decrease in kWh sales for the 2006 and 2005 fiscal years, respectively:

Change in kWh Deliveries for the fiscal year ended
(kWh in billions)	March 31, 2006			March 31, 2005
Retail sales		(1.6	)		(1.4	)
Delivery only sales		2.3			1.6
Total deliveries to ultimate customers		0.7			0.2
Sales for resale		(1.5	)		(2.1	)
Total deliveries		(0.8	)		(1.9	)

Gas revenues increased $229 million in the fiscal year ended March 31, 2006 from the prior fiscal year. This increase is primarily a result of higher prices of gas purchases which are being passed through to customers.

Gas revenues increased $28 million for the fiscal year ended March 31, 2005 from the prior fiscal year primarily due to higher prices of gas purchases which are being passed through to customers. This increase was affected by the elimination of a $6 million adjustment related to state net income tax recorded in the fiscal year ended March 31, 2004 and reversed in the fiscal year ended March 31, 2005.

The table below details components of the gas revenue fluctuation:

Change in Gas Revenue for the fiscal year ended
(in millions of dollars)	March 31, 2006			March 31, 2005
Cost of purchased gas	$	232		$	31
Delivery revenue		(2	)		(4	)
Other		(1	)		1
Total	$	229		$	28

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The change in the cost of purchased gas has no impact on the Company’s net income because the actual commodity costs are passed through to customers on a dollar-for-dollar basis.

Gas sales volumes for the fiscal year ended March 31, 2006, excluding transportation of customer-owned gas, decreased approximately 3.9 million Dekatherms (Dth), or a 6.4% decrease from the prior fiscal year. Gas sales for the fiscal year ended March 31, 2005, excluding transportation of customer-owned gas, decreased approximately 3.6 million Dth, or a 5.7% decrease from the fiscal year ended March 31, 2004. The decreased gas usage for the fiscal year ended March 31, 2006 compared with the fiscal year ended March 31, 2005 is partially due to the impacts of weather and to decreased use per customer as a result of higher natural gas prices, offset in part by the return of customers from alternate providers. The decreased gas usage for the fiscal year ended March 31, 2005 compared with the fiscal year ended March 31, 2004 is partially due to the impacts of weather and to the migration of customers to alternate providers.

OPERATING EXPENSES

Purchased electricity increased approximately $100 million for the fiscal year ended March 31, 2006 from the prior fiscal year. The volume of kWh purchased decreased 3.2 billion kWh, or 12% compared with the prior fiscal year, reflecting migration of customers to competitive electricity suppliers and the expiration of certain sales for resale purchased power contracts. This volume decrease was offset by a 22% increase in the price of electricity relative to the prior fiscal year.

Purchased electricity decreased approximately $227 million for the fiscal year ended March 31, 2005 from the prior fiscal year. The Company purchased less kWh of electricity versus the prior fiscal year because of the migration of customers to competitive electricity suppliers and the expiration of certain sales for resale purchased power contracts. This volume decrease was offset by a 2% increase in the price of electricity relative to the prior fiscal year.

Purchased gas expense increased approximately $232 million for the fiscal year ended March 31, 2006 from the prior fiscal year. This increase is primarily the result of increased gas prices during the year and an increase in the amount of gas sold off-system. The Company’s net cost per Dth, as charged to expense, including the effects of the gas cost deferral, increased to $9.92 in the fiscal year ended March 31, 2006 from $7.12 in the prior fiscal year. The increase due to price was slightly offset by decreased purchases.

Purchased gas expense increased approximately $31 million for the fiscal year ended March 31, 2005 compared with the fiscal year ended March 31, 2004. This increase is primarily a result of increased gas prices during the year. The Company’s net cost per Dth, as charged to expense, including the effects of the gas cost deferral, increased to $7.12 for the year ended March 31, 2005 from $6.61 in the prior fiscal year ended March 31, 2004.

For a discussion of hedging of gas purchases, see Item 7A. Quantitative and Qualitative Disclosures about Market Risk – “Gas Supply Price Risk.”

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Other operation and maintenance expense increased $9 million for the year ended March 31, 2006 from the prior fiscal year. The table below details components of this fluctuation.

	For the year		For the year
	ended		Ended
(in millions of dollars)	March 31, 2006		March 31, 2005			Change
Storm costs	$	18	$	—		$	18
Bad debt expense		42		45			(3	)
Payroll costs		260		277			(17	)
Recovery of pension settlement loss		—		(14	)		14
Consultants & contractors		90		101			(11	)
Materials and supplies		30		27			3
Transportation costs		28		25			3
Rents		28		25			3
Service quality penalties		9		4			5
Loss on sale of facilities		—		8			(8	)
Other		213		211			2
Total	$	718	$	709		$	9

The increase for the fiscal year ended March 31, 2006 is primarily due to higher non-recoverable storm related costs of $18 million and a one-time $14 million pension settlement loss recovery recorded in the prior year reflecting the PSC’s July 2004 approval for the Company to recover a portion of the $30 million pension settlement loss incurred in fiscal year 2003. These were partially offset by a decrease in payroll costs of $17 million primarily attributable to ongoing headcount reductions and reduced consultant and contractor costs of $11 million mostly due to merger related efficiencies. Also offsetting the increase was a reduction in bad debt expense of $3 million reflecting the Company’s strong focus on managing bad debts despite increased commodity costs and increased accounts receivable.

The Company is also subject to service quality standards with respect to reliability and certain aspects of customer service and safety. The Company works toward service quality standards that the state regulators expect us to achieve. If the Company falls below a prescribed standard, a penalty is incurred. The Company missed targets for reliability in fiscal years ended March 31, 2006 and 2005, incurring penalties of $9 million and $4 million, respectively.

Other operation and maintenance expense decreased $84 million for the fiscal year ended March 31, 2005 from the prior fiscal year. The decrease was primarily due to a $54 million decrease relating to one-time retiree benefit expenses (which includes the pension settlement loss recovery of $14 million mentioned above), a reduction in bad debt expense of $19 million which resulted from improved collection practices and $8 million of storm expenses recorded in the 2004 fiscal year with no similar expense recorded in fiscal year 2005. These decreases were offset by an $8 million loss on the sale of facilities in fiscal year 2005.

Depreciation and amortization expense increased $3 million for the fiscal year ended March 31, 2006 from the prior fiscal year because capital projects went into service. For the fiscal year ended March 31, 2005, depreciation and amortization expense remained constant relative to the prior fiscal year.

Amortization of stranded costs increased $15 million and $57 million for the fiscal years ended March 31, 2006 and March 31, 2005, respectively, from the prior fiscal years in accordance with the Merger Rate Plan. Under the Merger Rate Plan the stranded cost regulatory asset amortization period was established for recovery over the ten year period ending December 31, 2011. This asset is being amortized unevenly on an increasing, graduated schedule. See Item 8. Financial Statements and Supplementary Data — Note B — Rate and Regulatory Issues — “Stranded Costs” for a further discussion of the ratemaking treatment related to this regulatory asset.

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Other taxes decreased approximately $8 million for the fiscal year ended March 31, 2006 from the prior fiscal year primarily due to reduced gross receipts tax (GRT). This reduction in GRT is primarily due to lower rates and reduced tax base, partially offset by a slight increase in property taxes.

Other taxes decreased approximately $9 million for the fiscal year ended March 31, 2005 from the prior fiscal year primarily due to reduced GRT. This reduction in GRT is primarily due to lower rates and reduced revenues.

Income taxes increased $19 million for the fiscal year ended March 31, 2006 from the prior fiscal year primarily due to higher pre-tax book income offset by a $4 million benefit related to prior years’ tax return true-ups and settlements of tax audits. Income taxes increased $32 million for the fiscal year ended March 31, 2005 relative to the prior fiscal year primarily due to higher pre-tax book income offset by a $20 million decrease in prior years’ tax return true-ups.

OTHER INCOME (DEDUCTIONS), INTEREST AND PREFERRED DIVIDENDS

Other income (deductions) decreased $16 million for the fiscal year ended March 31, 2006 from the prior fiscal year and increased by $16 million for the year ended March 31, 2005 relative to the prior fiscal year, primarily due to a $9 million settlement of an estimated liability and an $8 million favorable adjustment to non-utility related income taxes which were recorded in the 2005 fiscal year with no similar adjustments recorded in the 2006 or 2004 fiscal years.

Interest charges decreased $21 million for the fiscal year ended March 31, 2006 from the prior fiscal year. The decrease is primarily due to maturing long-term debt replaced with affiliated company debt at lower interest rates which were partially offset by increased interest payments on short term debt due to higher interest rates.

Interest charges decreased $47 million for the fiscal year ended March 31, 2005 from the prior fiscal year. The decrease is primarily due to maturing long-term debt and to the early redemption of third-party debt which were replaced with affiliated company debt at lower interest rates and which were partially offset by increased interest payments on short-term debt because of increased average short-term borrowings and higher interest rates.

EFFECTS OF CHANGING PRICES

The Company’s financial results and financial position are impacted by inflation because of the amount of capital it typically needs and because its prices are regulated using a rate-base methodology that reflects the historical cost of utility plant.

The Company’s financial statements are based on historical events and transactions. The effects of inflation on most utilities, including the Company, are most significant in the areas of depreciation and utility plant. In addition, the Company would not replace these assets with identical assets because of technological advances and competitive and regulatory changes that have occurred. In light of these considerations, the depreciation charges in operating expenses do not reflect the cost of providing service if new facilities were installed. See “Long – Term Outlook” under “Liquidity and Capital Resources” below for a discussion of the Company’s future capital requirements.

LIQUIDITY AND CAPITAL RESOURCES

Short-Term Outlook: At March 31, 2006, the Company’s principal sources of liquidity included cash and cash equivalents of $11 million and accounts receivable of $654 million. The Company has a negative working

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capital balance of $461 million primarily due to $275 million of long-term debt due within one year and short-term debt due to affiliates of $579 million (see the intercompany money pool discussion below in Item 8). Cash is being generated from sales (via electric rates) to offset stranded cost amortization (non-cash expense). This excess cash is used to repay debt and for other operating needs. As discussed below, the Company believes it has sufficient cash flow and borrowing capacity to fund working capital deficits as necessary in the near term.

Net cash provided by operating activities decreased approximately $141 million for the fiscal year ended March 31, 2006 from the prior fiscal year. The primary reasons for the decrease in operating cash flow are:

• Decreased provision for deferred income taxes of $77 million primarily due to the expiration of federal bonus depreciation in December of 2004.

• Increased accounts receivable of $89 million primarily due to the higher cost of electricity and gas passed along to customers.

• Increased materials and supplies of $29 million primarily due to the higher cost of stored gas and the lower volume of gas sold relative to the prior fiscal year because of milder winter temperatures.

• Increased other regulatory assets of $128 million primarily due to higher commodity prices and timing differences between expenditures and their recovery from customers.

These were partially offset by:

• Increased net income (see income discussion above) of $54 million.

• Increased pension and other benefit plans expense of $7 million.

• Increased accounts payable and accrued expenses of $30 million.

• Increased accrued interest and tax expense of $60 million.

• Lower required funding of employee pension and other benefits of $14 million.

• Increased amortization of stranded costs of $15 million in accordance with the Merger Rate Plan.

• Increased depreciation and amortization expense of $3 million.

The Company’s net cash used in investing activities increased $119 million for the fiscal year ended March 31, 2006 from the comparable period in the prior fiscal year. This increase was primarily a result of increased restricted cash due to equity in hedge accounts related to the rise in the underlying commodity price.

The Company’s net cash used in financing activities decreased $258 million for the fiscal year ended March 31, 2006 from the comparable period in the prior fiscal year. This decrease resulted primarily from increased short-term debt to affiliates of $241 million.

Long-Term Outlook: The Company’s total capital requirements consist of amounts for its construction program, electricity and gas purchases, working capital needs and maturing debt issues. Generally, construction expenditure levels for the energy delivery business are consistent from year-to-year, however, the Company is embarking on a Reliability Enhancement Program, to improve performance and reliability, which will result in increased capital expenditures over the next five years.

The Company’s long-term debt due within one year is $275 million at March 31, 2006. In addition, construction expenditures planned within one year are estimated to be approximately $337 million. These capital requirements are planned to be financed primarily from internally generated funds and borrowings from other National Grid companies through the intercompany money pool.

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The following table summarizes long-term contractual cash obligations of the Company:

			Contractual obligations due in
			Less than		1 - 3		4 - 5
($’s in millions)	Total		one year		years		years		Thereafter
Long-term debt	$	2,925	$	275	$	800	$	700	$	1,150
Short-term debt due to affiliates*		579		579		N/A		N/A		N/A
Interest on long-term debt**		509		147		232		130		N/A
Electric purchase power commitments		4,144		456		854		606		2,228
Gas supply commitments		557		295		247		11		4
Derivative swap commitments***		537		247		290		N/A		N/A
Construction expenditures****		337		337		N/A		N/A		N/A
Total contractual cash obligations	$	9,588	$	2,336	$	2,423	$	1,447	$	3,382

*	Classified as a current liability because all borrowings are payable on demand.
**	Forecasted and actual amounts could differ due to changes in market conditions. Amounts beyond 5 years are not forecasted and, therefore, are not included.
***	Forecasted and actual amounts could differ due to changes in market conditions.
****	Represents budgeted amounts for which substantial commitments have been made. Amounts beyond 1 year are not considered contractual obligations and are therefore not included.

Expected contributions to trusts of the Company’s pension and post-retirement benefit plans (as disclosed in Item 8. Financial Statements and Supplementary Data — Note H — Employee Benefits) are not included in the above table.

See Item 8. Financial Statements and Supplementary Data — Note D — Commitments and Contingencies, for a detailed discussion of the electric purchase power commitments and the gas supply, storage and pipeline commitments, Note L — Derivatives and Hedging Activities for a detailed discussion of IPP and fossil/hydro swaps and Note E — Long-Term Debt for a detailed discussion of mandatory debt repayments.

The Company also has the ability to issue first mortgage bonds to the extent that there have been maturities or early redemptions of them since June 30, 1998. Through March 31, 2006, the Company had approximately $2.1 billion in such first mortgage bond maturities and early redemptions. This increased to $2.4 billion in May of 2006.

New Accounting Standards: In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R addresses the accounting for transactions in which a company receives employee services in exchange for (a) equity instruments of the company or (b) liabilities that are based on the fair value of the company’s equity instruments or that may be settled by the issuance of such equity instruments. SFAS No. 123R also eliminates the ability to account for share-based compensation transactions using Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and requires that such transactions be accounted for using a fair-value-based method. SFAS No. 123R was originally effective for public companies for interim and annual periods beginning after June 15, 2005; however, in April 2005 the SEC delayed the effective date of SFAS No. 123R to annual, rather than interim, periods that begin after June 15, 2005. The SEC’s new rule resulted in a six-month deferral for the Company. The adoption of SFAS No. 123R on April 1, 2006 does not have a material impact on its results of operations or its financial position.

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In March 2005, the FASB issued Interpretation No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations.” FIN 47 will result in: (a) more consistent recognition of liabilities relating to asset retirement obligations, (b) more information about expected future cash outflows associated with those obligations and (c) more information about investments in long-lived assets because additional asset retirement costs will be recognized as part of the carrying amounts of the assets.

A conditional retirement obligation, which is referred to in SFAS No. 143, “Accounting for Asset Retirement Obligations,” is defined in FIN 47 as a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional upon a future event that may or may not be within the entity’s control. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity has sufficient information to make a reasonable estimate of the fair value of an asset retirement obligation. FIN 47 is effective for the Company as of its March 31, 2006 fiscal year end. The Company has a $10 million asset retirement obligation reserve as of March 31, 2006 which does not have a material impact on the Company’s results of operations or financial position.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.” Previously, APB No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements,” defined the requirements for the accounting for and the reporting of a change in accounting principle. SFAS No. 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the period-specific effects of an accounting change on one or more individual prior periods presented, SFAS No. 154 requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement. SFAS No. 154 becomes effective for fiscal years ending after December 15, 2005. The Company adopted it as of its March 31, 2006 fiscal year.

On March 31, 2006, the FASB issued an Exposure Draft of proposed rules on employers’ accounting for defined benefit pensions and other postretirement benefit plans that would require employers to fully recognize the plan’s funded status on the balance sheet. If adopted as proposed, the new rules would be applied retroactively to prior financial statements presented and be effective for fiscal years ending after December 15, 2006. The new rules, if adopted as proposed, may significantly increase the Company’s recorded pension and other postretirement liabilities. Under the current rate agreements with the PSC, the Company would recover the additional pension costs from customers and therefore the costs would be recognized as a regulatory asset upon adoption. The comment period on this Exposure Draft ended on May 31, 2006. The Company is currently evaluating the Exposure Draft, and at this time cannot determine the full impact that the potential requirements of the Exposure Draft may have on its financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to certain market risks because of transactions conducted in the normal course of business. The financial instruments held or issued by the Company are used for investing, financing, hedging or cost control and not for trading.

Quantitative and qualitative disclosures are discussed by market risk exposure category:

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§	Interest Rate Risk
§	Commodity Price Risk
§	Equity Price Risk
§	Foreign Currency Exchange Risk

An Energy Procurement Risk Management Committee (EPRMC) was established to monitor and control efforts to manage commodity risks. This committee issues and oversees the Financial Risk Management Policy (the Policy) which outlines the parameters within which corporate managers are to engage in, manage and report on various areas of commodity risk exposure. At the core of the Policy is a condition that the Company will engage in activities at risk only to the extent that those activities fall within commodities and financial markets to which it has an actual market exposure in terms and in volumes consistent with its core business. That core business is to deliver energy, in the form of electricity and natural gas, to customers within the Company’s service territory. The policies of the Company may be revised as its primary markets continue to change, principally as increased competition is introduced and the role of the Company in these markets evolves.

Commodity Price Risk: The Company is exposed to commodity market price fluctuations related to: (1) the cost of electricity and natural gas for resale to its customers, and (2) the impact that natural gas, electricity and oil prices have on the swap contracts and one large non-Master Restructuring Agreement (MRA) IPP contract. For both gas and electricity, the Company reconciles and recovers commodity costs currently in rates to its customers who purchase the commodity. Where possible, the Company takes positions to mitigate expected price volatility but only to the extent that the quantities involved are based on expectations of delivery. The Company attempts to mitigate exposure through a program that hedges risks as appropriate. The Company does not speculate on movements in the underlying commodity prices. Commodity purchases are based on analyses performed in relation to expected customer deliveries for electricity and natural gas. The volume of commodities covered by hedging contracts does not exceed amounts needed for customer consumption in the normal course of business or to offset price movements in the contracts being hedged.

Large customers that continue to purchase electricity from the Company receive power from the NYISO at prevailing market prices and, in effect, assume the associated commodity price risk. For the remaining customers the Company meets a significant portion of its commodity supply responsibility through various physical and financial contracts. Some of these contracts are indexed to fuel prices, primarily natural gas. Although the current rate agreement allows for a pass-through of the commodity cost of power, the Company considers it prudent to perform certain hedging activities as a means of controlling cost volatility caused by the operation of these indexing mechanisms.

As part of the MRA, the Company entered into restated indexed swap contracts with eight IPPs. See Item 8. Financial Statements and Supplementary Data — Note L — Derivatives and Hedging Activities, for a more detailed discussion of these swap contracts.

The fair value of the liability under the swap contracts is based on the difference between projected future market prices and projected contract prices applied to the notional quantities and discounted to the present value. This liability was approximately $537 million and $619 million at March 31, 2006 and 2005, respectively, and is recorded on the Company’s balance sheets under both current and noncurrent liabilities. The decrease is primarily due to the revaluation of the contracts at March 31, 2006 and to normal contract settlements. The discount rate is a market-based rate representing the yield curve through the life of the contracts. Based on the PSC’s approval of the restated contracts as part of the MRA, including the indexed swap contracts, and the opportunity to recover the estimated indexed swap liability from customers, the Company recorded a corresponding regulatory asset. The amounts of the recorded liability and regulatory asset

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are sensitive to changes in anticipated future market prices and changes in the indices upon which the indexed swap contract payments are based.

If the indexed contract price increased or decreased by 1%, there would be a respective $11 million increase or decrease in the present value of the projected over-market exposure associated with these contracts. If the market prices increased or fell by 1%, there would be a respective $5 million decrease or increase in the projected over-market exposure associated with these contracts. If the discount rate was 0.5% higher or lower, the respective net present value of the projected over-market exposure associated with these contracts would decrease or increase by approximately $3.3 million.

The area of exposure to cash flow is in the indexing of the contract prices for the IPP indexed swaps and a non-MRA IPP where payments are based on gas prices. The contract payments under the IPP swaps and non-MRA IPP swaps are indexed to the costs of fuel, primarily natural gas. As fuel costs rise, the payments the Company makes under those contracts increase. The current rate plan allows the pass-through of the commodity cost of power to customers; however, the Company still considers it prudent to use certain financial instruments to limit the impact of commodity fluctuations on these payments.

The Company has taken steps to mitigate the potential impact that fuel prices would have on the payments for the IPP swaps and a physical power contract with a non-MRA IPP. To limit this exposure, the Company purchased NYMEX gas futures contracts and entered into fixed-for-floating swaps on gas-basis costs. To hedge the non-MRA IPP contract, the Company purchased NYMEX gas futures. See Item 8 — Financial Statements and Supplementary Data — Note L — Derivatives and Hedging Activities for a more detailed discussion of these contracts. As of March 31, 2006, gas futures have been purchased to hedge approximately 50% of the estimated amount needed to offset gas price changes in the period ended March 31, 2007. At March 31, 2005, the open NYMEX futures the Company had in place to hedge the payments under these contracts had a fair value pre-tax gain of $27 million.

Activity for the fair value of the NYMEX futures and gas basis swaps for the fiscal year ended March 31, 2006 is as follows:

	Hedges of IPP Swaps						Hedges Non-MRA IPP
	NYMEX Futures						NYMEX Futures
(in thousands of Dths and dollars)	Dth			Fair Value			Dth			Fair Value
March 31, 2005 asset balance		20,046.9		$	25,013.5			1,593.1		$	2,006.1
New contracts		38,939.0			(722.0	)		3,241.0			(60.0	)
Settled during period		(38,398.9	)		(49,397.5	)		(3,121.1	)		(4,036.1	)
March 31, 2006 asset (liability) balance		20,587.0		$	(25,106.0	)		1,713.0		$	(2,090.0	)

Gas Supply Price Risk: The cost of natural gas sold to customers fluctuates during the year with prices historically most volatile in the winter months. The Company’s gas rate agreement includes a provision for the collection or pass-back of increases or decreases in purchased gas costs. The PSC has also mandated that the Company attempt to reduce the price volatility in the gas commodity portion of customers’ bills. In response to this mandate, the Company’s Board of Directors has authorized the use of futures, options, and swaps to hedge against gas price fluctuations. The hedging program is consistent with the Policy and is monitored by the EPRMC.

The Company attempts to hedge approximately 50% of its forecasted average demand for the October to April period through a program using in-ground storage and financial instruments. NYMEX gas futures are the

22

financial instruments used by the Company. Each NYMEX futures contract represents 10,000 Dth of gas. At March 31, 2006 and 2005 the mark-to-market net open position of cash flow hedges for gas supply was a loss of $5 million and a gain of $7 million, respectively. There were 671 and 593 open futures contracts at March 31, 2006 and March 31, 2005, respectively.

The following table details the fair value activity for gas cash flow hedges for the fiscal year ended March 31, 2006:

Hedges of Gas Supply
	NYMEX Futures
(in thousands of dths and dollars)	Dth			Fair Value
March 31, 2005 asset balance		5,930.0		$	7,233.4
New Contracts		13,980.0			—
Settled during the period		(13,200.0	)		(30,127.0	)
Mark-to-market adjustments		—			17,534.8
March 31, 2006 asset (liability) balance		6,710.0		$	(5,358.8	)

The above activity coupled with the in-ground storage hedged approximately 50% of the Company’s average gas demand for the October to April period. The rest of the gas needs are met through market-based purchases that are subject to price fluctuations and which are mitigated by regulatory rate recovery for the cost of gas purchased.

The extent to which market price movement would affect the value of the hedges would be matched by an offsetting change in the anticipated gas purchased costs for the quantity of gas hedged. Therefore, for the quantities hedged, variations in market costs would not result in any significant impact on earnings.

Electricity Price Risk: The Company meets a substantial portion of its electricity requirements through a series of long-term physical and financial contracts. The remaining electricity requirements are purchased at market prices through the NYISO. If certain proscribed risk values are exceeded during a time when the Company forecasts a short power situation, the Company may use electricity swaps to lock in a price for electricity. In April 2003, the Company began utilizing NYMEX electricity swap contracts to hedge electricity purchases. The Company continues to evaluate the use of hedging instruments to manage the cost of electricity purchased. At March 31, 2006, the mark-to-market net open position of electricity swap contracts was a gain of $0.3 million.

Interest Rate Risk: The Company is exposed to changes in interest rates through several series of adjustable rate promissory notes and short-term borrowings. See Item 8. Financial Statements and Supplementary Data — Note E — Long-Term Debt and Note F – Short-Term Debt. Total adjustable rate promissory notes are currently valued at $575 million. There was $567 million of short term borrowing at March 31, 2006 from the intercompany money pool maintained by National Grid. At March 31, 2005 these borrowings totaled $401 million.

There is no interest rate cap on the promissory notes. The interest rates on short-term money pool borrowings are tied to the published, 30 day commercial paper rate with the amount borrowed from the National Grid money pool adjusted daily.

The Company also maintains long-term debt at fixed interest rates. A controlling factor on the exposure to interest rate variations is the mix of fixed to variable rate instruments maintained by the Company. For March 31, 2006 and 2005, adjustable rate instruments comprise 33.3% and 19.7% of total long-term debt, respectively.

23

In the aggregate at March 31, 2006 and 2005, variable rate instruments do not constitute a significant portion of total capitalization and debt, thereby limiting the Company’s exposure to interest rate fluctuations.

If interest rates averaged 1% more in the next fiscal year versus the fiscal year ended March 31, 2006, the Company’s interest expense would increase and income before taxes would decrease by approximately $11 million. This figure was derived by applying a hypothetical 1% variance to the variable rate debt of $575 million plus the short-term variable borrowings of $567 million at March 31, 2006. Changes in the actual cost of capital from levels assumed in rates would create either exposure or opportunity for the Company until these changes could be reflected in future prices.

Equity Price Risk: The Company currently has no equity price risk.

Foreign Currency Exchange Risk: The Company currently has no foreign currency exchange risk.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A. FINANCIAL STATEMENTS

• Report of Independent Registered Public Accounting Firm

• Consolidated Statements of Operations, Consolidated Statements of Comprehensive Income and Consolidated Statements of Retained Earnings for each of the three years in the period ended March 31, 2006.

• Consolidated Balance Sheets at March 31, 2006 and 2005.

• Consolidated Statements of Cash Flows for each of the three years in the period ended March 31, 2006.

• Notes to Consolidated Financial Statements.

24

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors of
Niagara Mohawk Power Corporation:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Niagara Mohawk Power Corporation and its subsidiaries at March 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP

New York, New York
June 29, 2006

25

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Consolidated Statements of Operations
(In thousands of dollars)

	For the			For the		For the
	year ended			year ended		year ended
	March 31,			March 31,		March 31,
	2006			2005		2004
Operating revenues:
Electric	$	3,306,942		$	3,117,156	$	3,284,017
Gas		1,037,081			808,015		779,600
Total operating revenues		4,344,023			3,925,171		4,063,617
Operating expenses:
Purchased electricity		1,464,626			1,364,813		1,591,652
Purchased gas		741,419			509,543		478,647
Other operation and maintenance		717,745			708,606		793,110
Depreciation and amortization		203,994			200,793		200,650
Amortization of stranded costs		266,816			251,499		194,114
Other taxes		209,553			217,993		227,006
Income taxes		190,194			171,230		138,843
Total operating expenses		3,794,347			3,424,477		3,624,022
Operating income		549,676			500,694		439,595
Other income (deductions), net		(7,758	)		8,347		(7,198	)
Operating and other income		541,918			509,041		432,397
Interest:
Interest on long-term debt		138,415			169,585		220,781
Interest on debt to associated companies		75,358			66,283		55,282
Other interest		11,069			9,924		16,644
Total interest expense		224,842			245,792		292,707
Net income		317,076			263,249		139,690
Dividends on preferred stock		1,626			2,928		4,430
Income available to common shareholder	$	315,450		$	260,321	$	135,260

Consolidated Statements of Comprehensive Income
(In thousands of dollars)

	For the			For the			For the
	year ended			year ended			year ended
	March 31,			March 31,			March 31,
	2006			2005			2004
Net income	$	317,076		$	263,249		$	139,690
Other comprehensive income (loss), net of taxes:
Unrealized gains (losses) on securities		(337	)		732			1,731
Hedging activity		4,009			14,557			2,425
Change in additional minimum pension liability		358			—			(1,557	)
Reclassification adjustment for gains included in net income		(21,807	)		(4,943	)		—
Total other comprehensive income (loss)		(17,777	)		10,346			2,599
Comprehensive income	$	299,299		$	273,595		$	142,289

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

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

26

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Consolidated Statements of Retained Earnings
(In thousands of dollars)

	For the			For the			For the
	year ended			year ended			year ended
	March 31,			March 31,			March 31,
	2006			2005			2004
Retained earnings at beginning of period	$	473,287		$	220,966		$	85,706
Net income		317,076			263,249			139,690
Dividends on preferred stock		(1,626	)		(2,928	)		(4,430	)
Dividend to Niagara Mohawk Holdings, Inc.		—			(8,000	)		—
Retained earnings at end of period	$	788,737		$	473,287		$	220,966

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

27

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Consolidated Balance Sheets
(In thousands of dollars)

	March 31,		March 31,
	2006		2005
ASSETS
Utility plant, at original cost:
Electric plant	$	5,658,705	$	5,399,412
Gas plant		1,580,204		1,532,441
Common plant		309,053		333,922
Total utility plant		7,547,962		7,265,775
Less: Accumulated depreciation and amortization		2,247,350		2,108,379
Net utility plant		5,300,612		5,157,396
Goodwill (Note A)		1,214,576		1,224,025
Pension intangible		36,885		40,339
Other property and investments		47,379		55,048
Current assets:
Cash and cash equivalents		10,847		19,922
Restricted cash (Note A)		66,393		7,367
Accounts receivable (less reserves of $123,310 and $126,084, respectively, and including receivables from associated companies of $10,238 and $6,654, respectively)		653,652		571,552
Materials and supplies, at average cost:
Gas storage		23,576		3,498
Other		21,356		17,739
Derivative instruments (Note A and L)		317		35,326
Prepaid taxes		—		44,273
Current deferred income taxes (Note G)		168,354		307,431
Regulatory asset — swap contracts		246,551		203,558
Other		13,662		9,772
Total current assets		1,204,708		1,220,438
Regulatory and other non-current assets:
Regulatory assets (Note B):
Merger rate plan stranded costs		2,486,590		2,765,392
Swap contracts regulatory asset		290,902		415,394
Regulatory tax asset		106,624		79,933
Deferred environmental restoration costs		399,630		431,000
Pension and postretirement benefit plans		527,829		501,358
Additional minimum pension liability		75,252		194,302
Loss on reacquired debt		59,521		67,162
Other		499,716		330,094
Total regulatory assets		4,446,064		4,784,635
Other non-current assets		30,744		36,481
Total regulatory and other non-current assets		4,476,808		4,821,116
Total assets	$	12,280,968	$	12,518,362

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

28

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Consolidated Balance Sheets
(In thousands of dollars)

	March 31,			March 31,
	2006			2005
CAPITALIZATION AND LIABILITIES
Capitalization:
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
Additional paid-in capital		2,929,501			2,929,501
Accumulated other comprehensive income (loss) (Note C)		(4,816	)		12,961
Retained earnings		788,737			473,287
Total common stockholder’s equity		3,900,787			3,603,114
Preferred equity (Note I):
Cumulative preferred stock ($100 par value, optionally redeemable)		41,170			41,170
Authorized - 3,400,000 shares
Issued and outstanding - 411,715 shares
Long-term debt (Note E)		1,448,934			1,723,569
Long-term debt to affiliates (Note E)		1,200,000			1,200,000
Total capitalization		6,590,891			6,567,853
Current liabilities:
Accounts payable (including payables to associated companies of $28,315 and $36,440, respectively)		275,223			271,275
Customers’ deposits		32,345			26,900
Accrued interest		65,952			82,945
Short-term debt to affiliates (Note F)		578,900			400,500
Current portion of liability for swap contracts (Note A and L)		246,551			203,558
Current portion of long-term debt (Note E)		275,000			550,420
Derivative instruments (Note A and L)		32,555			—
Accrued taxes		61,704			—
Other		97,284			107,871
Total current liabilities		1,665,514			1,643,469
Non-current liabilities:
Accumulated deferred income taxes (Note G)		1,687,360			1,711,630
Liability for swap contracts (Note A and L)		290,902			415,394
Employee pension and other benefits (Note H)		628,850			671,053
Liability for environmental remediation costs		399,630			431,000
Nuclear fuel disposal costs		150,642			145,562
Cost of removal regulatory liability (Note N)		337,995			318,455
Other		529,184			613,946
Total other non-current liabilities		4,024,563			4,307,040
Commitments and contingencies (Note D)		—			—
Total capitalization and liabilities	$	12,280,968		$	12,518,362

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

29

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flows
(In thousands of dollars)

	Year			Year			Year
	ended			ended			ended
	March 31, 2006			March 31, 2005			March 31, 2004
Operating activities:
Net income	$	317,076		$	263,249		$	139,690
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		203,994			200,793			200,650
Amortization of stranded costs		266,816			251,499			194,114
Provision for deferred income taxes		103,474			180,722			148,435
Pension and other benefit plans expense		107,208			100,143			100,484
Cash paid to pension and postretirement benefit plan trusts		(95,500	)		(109,330	)		(266,139	)
Changes in operating assets and liabilities:
Net accounts receivable		(82,100	)		7,102			(35,374	)
Materials and supplies		(23,695	)		5,703			(5,744	)
Accounts payable and accrued expenses		(1,194	)		(31,513	)		(74,946	)
Accrued interest and tax		44,711			(15,276	)		(10,706	)
Other regulatory assets		(169,622	)		(41,667	)		(46,137	)
Other, net		72,431			73,565			5,044
Net cash provided by operating activities		743,599			884,990			349,371
Investing activities:
Construction additions		(269,941	)		(266,012	)		(317,302	)
Change in restricted cash		(59,026	)		4,796			13,187
Other investments		8,023			2,651			6,563
Other, net		(58,084	)		(1,640	)		(17,294	)
Net cash used in investing activities		(379,028	)		(260,205	)		(314,846	)
Financing activities:
Dividends paid on preferred stock		(1,626	)		(2,928	)		(4,430	)
Dividends paid on common stock to Holdings		—			(8,000	)		—
Reductions in long-term debt		(550,420	)		(532,620	)		(1,319,490	)
Proceeds from long-term debt		—			—			45,600
Proceeds from long-term debt to affiliates		—			—			700,000
Redemption of preferred stock		—			(25,155	)		(33,903	)
Net change in short-term debt to affiliates		178,400			(63,000	)		265,500
Equity contribution from parent		—			—			309,000
Net cash used in financing activities		(373,646	)		(631,703	)		(37,723	)
Net decrease in cash and cash equivalents		(9,075	)		(6,918	)		(3,198	)
Cash and cash equivalents at beginning of period		19,922			26,840			30,038
Cash and cash equivalents at end of period	$	10,847		$	19,922		$	26,840
Supplemental disclosures of cash flow information:
Interest paid	$	244,499		$	258,735		$	336,147
Income taxes received	$	(16,210	)	$	(54,940	)	$	(13,904	)

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

30

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE A — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation: Niagara Mohawk Power Corporation (the Company) is subject to regulation by the New York State Public Service Commission (PSC) and the Federal Energy Regulatory Commission (FERC) with respect to its rates for service under a methodology that establishes prices based on the Company’s cost. The Company’s accounting policies conform to Generally Accepted Accounting Principles in the United States of America (GAAP), including the accounting principles for rate-regulated entities with respect to the Company’s transmission, distribution and gas operations (regulated business), and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities.

Niagara Mohawk Holdings, Inc. (Holdings), the parent company of the Company, is a wholly owned subsidiary of National Grid USA (National Grid). National Grid is a wholly owned subsidiary of National Grid plc (formerly known as National Grid Transco plc).

The Company’s consolidated financial statements include its accounts as well as those of its wholly owned subsidiaries. Inter-company balances and transactions have been eliminated.

Goodwill: The acquisition of the Company was accounted for by the purchase method, the application of which, including the recognition of goodwill, was recognized on the books of the Company, the most significant subsidiary of Holdings. The merger transaction resulted in approximately $1.2 billion of goodwill. In accordance with Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets”, the Company reviews its goodwill annually for impairment and when events or circumstances indicate that the asset may be impaired. The Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the performance of the annual goodwill impairment test. The result of the annual analysis determined that no adjustment to the goodwill carrying value was required. As a result of a settled IRS audit of pre-merger years, the Company recorded a $9 million adjustment to goodwill related to a pre-merger tax contingency.

Use of Estimates: The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Utility Plant: The cost of additions to utility plant and replacements of retirement units of property are capitalized. Costs include direct material, labor, overhead and AFUDC (see below). Replacement of minor items of utility plant and the cost of current repairs and maintenance are charged to expense. Whenever utility plant is retired, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation.

Allowance for Funds Used During Construction (AFUDC): The Company capitalizes AFUDC as part of construction costs in amounts equivalent to the cost of funds devoted to plant under construction for its regulated business. AFUDC represents an allowance for the cost of funds used to finance

31

construction. AFUDC is capitalized in “Utility plant” with offsetting non-cash credits to “Other interest” and “Other income (deductions)” on the Consolidated Statement of Operations. This method is in accordance with an established rate-making practice under which a utility is permitted a return on, and the recovery of, prudently incurred capital costs through their ultimate inclusion in rate base and in the provision for depreciation. AFUDC rates are determined in accordance with FERC and PSC regulations. The AFUDC rates in effect at March 31, 2006 and 2005 were 3.49% and 1.59%, respectively. AFUDC is segregated into its two components, borrowed funds and other funds, and is reflected in the “Other interest” and “Other income (deductions)” sections, respectively, in the Company’s Consolidated Statements of Operations. The amounts of AFUDC credits were recorded as follows:

	Year Ended		Year Ended		Year Ended
	March 31,		March 31,		March 31,
(In thousands of dollars)	2006		2005		2004
Other income (deductions)	$	—	$	1	$	(9	)
Other interest		2,040		606		565

Depreciation: For accounting and regulatory purposes, the Company’s depreciation is computed on the straight-line basis using the average service lives. The Company performs depreciation studies to determine service lives of classes of property and adjusts the depreciation rates when necessary.

The weighted average service life, in years, for each asset category is presented in the table below:

	Year Ended		Year Ended		Year Ended
	March 31,		March 31,		March 31,
	2006		2005		2004
Asset Category:
Electric		34		35		34
Gas		42		43		44
Common		20		21		17

Revenues: The Company bills its customers on a monthly cycle basis at approved tariffs based on energy delivered and a minimum customer service charge. Revenues are determined based on these bills plus an estimate for unbilled energy delivered between the cycle billing date and the end of the accounting period. The unbilled revenues included in accounts receivable at March 31, 2006 and 2005 was approximately $133 million and $110 million, respectively.

The Company recognizes changes in accrued unbilled electric revenues in its results of operations. Pursuant to the Company’s 2000 multi-year gas settlement (which ended December 2004, with the Company having the right to request a change in rates at any time, if needed) changes in accrued unbilled gas revenues are deferred. At March 31, 2006 and 2005, approximately $6 million and $7 million, respectively, of unbilled gas revenues remain unrecognized in results of operations. The

32

Company cannot predict when unbilled gas revenues will be allowed to be recognized in results of operations.

In August 2001, the PSC approved certain rate plan changes. The changes allowed for certain commodity-related costs to be passed through to customers beginning September 2001. At the same time, a transmission revenue adjustment mechanism was implemented which reconciles actual and rate forecast transmission revenues for pass-back to, or recovery from, customers. The commodity adjustment clause and the transmission revenue adjustment mechanism remain in effect under the Merger Rate Plan which became effective upon the closing of the merger on January 31, 2002.

The PSC approved a multi-year gas rate settlement agreement (amended through the Company’s Merger Rate Plan and ended in December 2004 with the Company having the right to request a change in rates at any time, if needed) in July 2000 that includes a provision for the continuation of a full gas cost collection mechanism, effective August 2000. This gas cost collection mechanism was originally reinstated in an interim agreement that became effective November 1999. Such gas cost collection mechanism continues under the Merger Rate Plan. The Company’s gas cost collection mechanism provides for the collection or pass-back of increases or decreases in purchased gas costs.

Federal and State Income Taxes: Regulated federal and state income taxes are recorded under the provisions of Financial Accounting Standards Board (FASB) SFAS No. 109 “Accounting for Income Taxes”. Income taxes have been computed utilizing the asset and liability approach that requires the recognition of deferred tax assets and liabilities for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Deferred investment tax credits are amortized over the useful life of the underlying property.

Service Company Charges: National Grid USA Service Company, Inc., an affiliated service company, has furnished services to the Company at the cost of such services since the merger with National Grid. These costs approximated $160 million and $138 million for the years ended March 31, 2006 and 2005, respectively.

Cash and Cash Equivalents: The Company considers all highly liquid investments, purchased with an original maturity of three months or less, to be cash and cash equivalents.

Restricted Cash: Restricted cash consists of margin accounts for hedging activity, health care claims deposits, New York State Department of Conservation securitization for certain site cleanup, and worker’s compensation premium deposits. The $59 million increase in restricted cash for the fiscal year ended March 31, 2006 was primarily due to increased equity in hedge accounts related to the rise in underlying commodity prices.

Derivatives: The Company accounts for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities”, and SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” as amended. Under the provisions of SFAS No. 133, all derivatives except those qualifying for the normal purchase/normal sale exception are recognized on the balance sheet at their fair value. Fair value is determined using current quoted market prices. If a contract is designated as a cash flow hedge, the change in its market value is generally

33

deferred as a component of other comprehensive income until the transaction it is hedging is completed. Conversely, the change in the market value of a derivative not designated as a cash flow hedge is deferred as a regulatory asset or liability as the Company has received approval from the PSC to establish a regulatory asset or liability for derivative instruments that did not qualify for hedge accounting and were the result of regulatory rulings. A cash flow hedge is a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. To qualify as a cash flow hedge, the fair value changes in the derivative must be expected to offset 80% to 120% of the changes in fair value or cash flows of the hedged item.

Comprehensive Income (Loss): Comprehensive income (loss) is the change in the equity of a company, not including those changes that result from shareholder transactions. While the primary component of comprehensive income (loss) is reported net income or loss, the other components of comprehensive income (loss) relate to changes in additional minimum pension liability, deferred gains and losses associated with hedging activity, and unrealized gains and losses associated with certain investments held as available for sale. See Note C — Accumulated Other Comprehensive Income (Loss).

Additional Minimum Pension Liability: Additional minimum pension liability is recognized under SFAS No. 87, “Employers’ Accounting for Pensions”. Under current rate agreements with the PSC, the Company recovers pension costs from customers and therefore has recognized its additional minimum pension liability (AML) for its qualified plan as a regulatory asset. The additional minimum pension liability for its non-qualified plan is recognized as a component of accumulated other comprehensive income.

Power Purchase Agreements: The Company accounts for its power purchase agreements, which are not deemed to be derivatives or leases, as executory contracts. The Company assesses several factors in determining how to account for its power purchase contracts. These factors include:

• the term of the contract compared to the economic useful life of the facility generating the electricity;

• the involvement, if any, that the Company has in operating the facility;

• the amount of any fixed payments the Company must make, even if the facility does not generate electricity; and

• the level of control the Company has over the amount of electricity generated by the facility, and who bears the risk in the event the facility is unable to generate.

New Accounting Standards: In December 2004, the FASB issued 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 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

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April 2005 the SEC delayed the effective date of SFAS No. 123R to annual, rather than interim, periods that begin after June 15, 2005. The SEC’s new rule resulted in a six-month deferral for the Company. The adoption of SFAS No. 123R at April 1, 2006 does not have a material impact on its results of operations or its financial position.

In March 2005, the FASB issued Interpretation No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations.” FIN 47 will result in: (a) more consistent recognition of liabilities relating to asset retirement obligations, (b) more information about expected future cash outflows associated with those obligations and (c) more information about investments in long-lived assets because additional asset retirement costs will be recognized as part of the carrying amounts of the assets.

A conditional retirement obligation, which is referred to in SFAS No. 143, “Accounting for Asset Retirement Obligations,” is defined in FIN 47 as a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional upon a future event that may or may not be within the entity’s control. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity has sufficient information to make a reasonable estimate of the fair value of an asset retirement obligation. FIN 47 is effective for the Company as of its March 31, 2006 fiscal year end. The Company has a $10 million Asset Retirement Obligation reserve as of March 31, 2006 which does not have a material impact on the Company’s results of operations or financial position.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.” Previously, APB No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements,” defined the requirements for the accounting for and the reporting of a change in accounting principle. SFAS No. 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the period-specific effects of an accounting change on one or more individual prior periods presented, SFAS No. 154 requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement. SFAS No. 154 becomes effective for fiscal years ending after December 15, 2005 and the Company adopted it as of its March 31, 2006 fiscal year.

On March 31, 2006, the FASB issued an Exposure Draft of proposed rules on employers’ accounting for defined benefit pensions and other postretirement benefit plans that would require employers to fully recognize the plan’s funded status on the balance sheet. If adopted as proposed, the new rules would be applied retroactively to prior financial statements presented and be effective for fiscal years ending after December 15, 2006. The new rules, if adopted as proposed, may significantly increase the Company’s recorded pension and other postretirement liabilities. Under the current rate agreements with the PSC, the Company would recover the additional pension costs from customers and therefore the costs would be recognized as a regulatory asset upon adoption. The comment period on this Exposure Draft ended on May 31, 2006. The Company is currently evaluating the Exposure Draft, and at this time cannot

35

determine the full impact that the potential requirements of the Exposure Draft may have on its financial statements.

Reclassifications: Certain amounts from prior fiscal years have been reclassified on the accompanying consolidated financial statements to conform to the fiscal 2006 presentation.

NOTE B — RATE AND REGULATORY ISSUES

The Company’s financial statements conform to GAAP, including the accounting principles for rate-regulated entities that apply to its regulated operations. SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” permits a public utility that is regulated on a cost-of-service basis to defer certain costs it would otherwise charge to expense, if authorized to do so by the regulator. These deferred costs are known as regulatory assets. The Company’s regulatory assets were approximately $4.7 billion as of March 31, 2006 and $5.0 billion as of March 31, 2005. These regulatory assets are probable of recovery under the Company’s rate plans. The Company believes the prices it will charge for electric service in the future, including the CTCs, will be sufficient to recover and earn a return on the Merger Rate Plan’s stranded regulatory assets over their planned amortization periods, assuming no unforeseen reduction in demand or bypass of the CTC exit fees. The Company’s ongoing electricity business continues to be rate-regulated on a cost-of-service basis under the Merger Rate Plan and, accordingly, the Company continues to apply SFAS No. 71 to it. In addition, the Company’s Independent Power Producer contracts, and the Purchased Power Agreements, which were entered into when the Company exited the power generation business, continue to be the obligations of the regulated business.

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

On July 29, 2005, the Company filed its biannual CTC reset and deferral account recovery filing to reset rates charged to customers beginning January 1, 2006. The Company resets its CTC every two years under its Merger Rate Plan. The CTC reset is intended to account for changes in forecasted electricity and natural gas commodity prices, and the effects those changes have on the Company’s above market payments under legacy power contracts that otherwise would be stranded. In addition, the Merger Rate Plan allows the Company to recover amounts exceeding $100 million in its deferral accounts (as projected through the end of each two-year CTC reset period through the end of the Merger Rate Plan). In the July 29, 2005 filing, the Company included a proposal to recover the excess balance of the deferral accounts as of June 30, 2005 of $196 million and a projection through the end of the two year period of $373 million. 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 2006 and $200 million in 2007. For 2006, the deferral-related surcharge was included in rates beginning in April and the $100 million will be collected over the last nine months of the 2006 calendar

36

year. An audit of the deferral amount by the DPS Staff is ongoing. A formal hearing process has been established before a hearing officer at the PSC to litigate the levels in the deferral account. Under the hearing schedule, the Staff will be filing testimony setting forth its initial adjustments in early August. The Company will continue to defer costs and revenues, as applicable, through the end of the Merger Rate Plan on December 31, 2011. The Company’s future filings for recovery of deferred amounts are subject to regulatory review and approval.

Stranded Costs: Under the Merger Rate Plan, a regulatory asset was established that included the costs of the Master Restructuring Agreement (MRA), the cost of any additional IPP contract buyouts and the deferred loss on the sale of the Company’s generation assets. The MRA represents the cost to terminate, restate or amend IPP contracts. The Company is also permitted to defer and amortize the cost of any additional IPP contract buyouts. Beginning February 1, 2002, the Merger Rate Plan stranded costs regulatory asset is being amortized unevenly over ten years with larger amounts being amortized in the latter years, consistent with projected recovery through rates.

Regulatory Tax Asset: The regulatory tax asset represents the expected future recovery from ratepayers of the tax consequences of temporary differences between the recorded book basis and the tax basis of assets and liabilities. This amount is primarily timing differences related to depreciation. These amounts are recovered and amortized as the related temporary differences reverse.

Deferred Environmental Restoration Costs: This regulatory asset represents deferred costs associated with the Company’s share of the estimated costs to investigate and perform certain remediation activities at sites with which it may be associated. The Company’s rate plans provide for specific rate allowances for these costs, with variances deferred for future recovery or pass-back to customers. The Company believes future costs, beyond the expiration of current rate plans, will continue to be recovered through rates.

Pension and Post-retirement Benefit Plans: Excess costs of the Company’s pension and post-retirement benefits plans over amounts received in rates are deferred to a regulatory asset to be recovered in a future period.

Additional Minimum Pension Liability: The offset to any additional minimum pension liability associated with the Company’s qualified pension plan is applied to a regulatory asset on a pre-tax basis instead of being applied on an after-tax basis to other comprehensive income.

Loss on Reacquired Debt: The loss on reacquired debt regulatory asset represents the costs to redeem certain long-term debt securities which were retired prior to maturity. These amounts are amortized ratably as interest expense over the lives of the related issues in accordance with PSC directives.

Other: Included in the other regulatory asset is the accumulation of numerous miscellaneous regulatory deferrals, income earned on gas rate sharing mechanisms, the incentive earned on the sale of the fossil and hydro generation assets and certain New York Independent System Operator (NYISO) costs that were deferred for future recovery.

See Notes D, H and L for a discussion of regulatory asset accounts — Deferred environmental restoration costs, Pensions and post-retirement benefits plans and Derivatives, respectively.

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NOTE C — ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

	Unrealized
	Gains (Losses)									Total
	On			Additional						Accumulated
	Available-for-			Minimum						Other
	Sale			Pension			Cash Flow			Comprehensive
(in thousands of dollars)	Securities			Liability			Hedges			Income (Loss)
March 31, 2004 balance	$	1,147		$	(1,557	)	$	3,025		$	2,615
Unrealized gains (losses) on securities, net of tax		732									732
Hedging activity, net of tax								14,557			14,557
Reclassification adjustment for gain included in net income, net of tax		(173	)					(4,770	)		(4,943	)
March 31, 2005 balance	$	1,706		$	(1,557	)	$	12,812		$	12,961
Unrealized gains (losses) on securities, net of tax		(337	)								(337	)
Hedging activity, net of tax								4,009			4,009
Change in additional minimum pension liability, net of tax					358						358
Reclassification adjustment for gain included in net income, net of tax		(233	)					(21,574	)		(21,807	)
March 31, 2006 balance	$	1,136		$	(1,199	)	$	(4,753	)	$	(4,816	)

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

	For the			For the			For the
	year ended			year ended			year ended
	March 31,			March 31,			March 31,
(in thousands of dollars)	2006			2005			2004
Investment activities	$	225		$	(488	)	$	(1,127	)
Hedging activities		(2,673	)		(9,705	)		42
Change in additional minimum pension liability		(239	)		—			1,038
Reclassification adjustment for gain included in net income		14,538			3,295			(1,685	)

NOTE D — COMMITMENTS AND CONTINGENCIES

Long-Term Contracts for the Purchase of Electric Power: The Company has several types of long-term contracts for the purchase of electric power. The Company’s commitments under these long-term contracts, as of March 31, 2006, are summarized in the table below. The Company did not enter into any new agreements in fiscal 2006 or 2005. For a detailed discussion of the financial swap agreements that the Company has entered into to hedge the costs of purchased electricity (which are not included in the table below), see Note L — Derivatives and Hedging Activities.

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(in thousands of dollars)
Fiscal Year
Ended	Estimated
March 31,	Payments
2007	$	455,823
2008		439,435
2009		414,523
2010		344,111
2011		262,021
Thereafter		2,228,199

If the Company needs any additional energy to meet its load, it can purchase the electricity from other IPPs, utilities, energy merchants or through the NYISO at market prices. Substantially all of these contracts require power to be delivered before the Company is obligated to make payment.

Gas Supply, Storage and Pipeline Commitments: In connection with its regulated gas business, the Company has long-term commitments with a variety of suppliers and pipelines to purchase gas commodity, provide gas storage capability and transport gas commodity on interstate gas pipelines.

     The table below sets forth the Company’s estimated commitments at March 31, 2006 for each of the next five years and thereafter.

(in thousands of dollars)
Fiscal Year
Ended			Gas Storage/
March 31,	Gas Supply		Pipeline
2007	$	245,259	$	50,000
2008		195,036		46,600
2009		—		5,310
2010		—		5,310
2011		—		5,310
Thereafter		—		4,324

With respect to firm gas supply commitments, the amounts are based upon volumes specified in the contracts giving consideration to the minimum take provisions. Commodity prices are based on New York Mercantile Exchange quotes and reservation charges, when applicable. Storage and pipeline capacity commitments’ amounts are based upon volumes specified in the contracts and represent demand charges priced in currently filed tariffs. At March 31, 2006, the Company’s firm gas supply commitments have varying expiration dates, the latest of which is March 2008. The gas storage and transportation commitments have varying expiration dates with the latest being October 2012.

Environmental Contingencies: The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations. Like many other industrial companies, the Company’s transmission and distribution business uses or generates some hazardous and potentially hazardous wastes and by-products. Under federal and state Superfund laws, potential liability for the historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.

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The Environmental Protection Agency (EPA), Department of Environmental Conservation (DEC), as well as private entities have alleged that the Company is a potentially responsible party under state or federal law for the remediation of an aggregate of approximately 100 sites, including 51 of which are Company owned. The Company’s most significant liabilities relate to manufactured gas plant (MGP) facilities formerly owned or operated by the Company’s previous owners. The Company is currently investigating and remediating, as necessary, 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 environmental laws will not have a material impact on its results of operations or its financial condition. The Company’s Merger Rate Plan provides for the continued application of deferral accounting for variations in spending from amounts provided in rates related to these environmental obligations. As a result, the Company has recorded a regulatory asset representing the investigation, remediation and monitoring obligations it expects to recover from ratepayers.

The Company is pursuing claims against other potentially responsible parties to recover investigation and remediation costs it believes are the obligations of those parties. The Company cannot predict the success of such claims, however. As of March 31, 2006 and 2005, the Company has accrued liabilities related to its environmental obligations of $400 million and $431 million, respectively, which is reflected in the Company’s Consolidated Balance Sheets. The decrease in the accrued liabilities was primarily due to the payments made for costs which were previously accrued. The potential high end of the range at March 31, 2006 is presently estimated at approximately $526 million.

Nuclear Contingencies: As of March 31, 2006 and 2005, the Company has a liability of $151 million and $146 million, respectively, in other non-current liabilities for the disposal of nuclear fuel irradiated prior to 1983. In January 1983, the Nuclear Waste Policy Act of 1982 (the Nuclear Waste Act) established a cost of $.001 per kWh of net generation for current disposal of nuclear fuel and provides for a determination of the Company’s liability to the U.S. Department of Energy (DOE) for the disposal of nuclear fuel irradiated prior to 1983. The Nuclear Waste Act also provides three payment options for liquidating such liability and the Company has elected to delay payment, with interest, until the year in which Constellation Energy Group Inc., which purchased the Company’s nuclear assets, initially plans to ship irradiated fuel to an approved DOE disposal facility. Progress in developing the DOE facility has been slow and it is anticipated that the DOE facility will not be ready to accept deliveries until at least 2010.

Legal Matters:

Station Service Cases (Niagara Mohawk Power Corp. v. Huntley Power L.L.C. et al., FERC Docket No. EL03-27; AES Somerset, L.L.C. v. Niagara Mohawk Power Corp., FERC Docket No. EL03-204; Nine Mile Point Nuclear Station, L.L.C. v. Niagara Mohawk Power Corp., FERC Docket No. EL03-234; Keyspan-Ravenswood, Inc. v. NYISO, FERC Docket No. EL01-50-004.) A number of generators have complained or withheld payments associated with the Company’s delivery of station service to their generation facilities, arguing that they should be permitted to bypass its retail charges. The FERC issued two orders on complaints filed by the Company’s station service customers in December 2003, allowing two generators to net their station service electricity over a 30-day period and to avoid state-authorized charges for deliveries made over distribution facilities. A third order in January 2005

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involves affiliates of NRG Energy, Inc. These orders directly conflict with the Company’s state-approved tariffs and the orders of the PSC on station service rates. The orders, if finally upheld, will permit these generators to bypass the Company’s state-jurisdictional station service charges for electricity, including those set forth in the filing that was approved by the PSC on November 25, 2003. In the aggregate, the Company is owed approximately $58 million as of March 31, 2006. The Company appealed these orders to the U.S. Court of Appeals for the District of Columbia Circuit, and the matters were consolidated for appeal. Oral argument was heard on April 10, 2006, and on June 23, 2006, the Court issued a decision upholding the FERC’s orders. The Company is reviewing the decision and considering whether to seek rehearing or further review.

The Court’s order upholding the FERC orders has increased the risk that generators will be able to bypass local distribution company charges (including stranded cost recovery charges) when receiving service through the NYISO. Although the Staff and other parties may challenge the Company’s position, in the event the FERC orders are finally upheld, the Company believes that the provision in the rate plan that permits the Company to recover lost revenues resulting from a change in law or regulation would permit it to recover the lost revenues that result from the FERC orders. These amounts are subject to regulatory review and challenge as part of the ongoing audit of the Company’s deferral account balance in accordance with the Merger Rate Plan.

NOTE E — LONG-TERM DEBT

Long-term debt consisted of the following at March 31, 2006 and 2005:

(in thousands of dollars)
			March 31,			March 31,
Series		Due	2006			2005
First Mortgage Bonds:
6 5/8%		July 2005	$	—		$	110,000
9 3/4%		November 2005		—			137,981
7 3/4%	(1)	May 2006		275,000			275,000
5.15%	(2)	November 2025		75,000			75,000
Total First Mortgage Bonds				350,000			597,981
Senior Notes(3):
7.63%		October 2005		—			302,439
8.88%		May 2007		200,000			200,000
7.75%		October 2008		600,000			600,000
Total Senior Notes			$	800,000		$	1,102,439
Pollution Control Revenue Bonds-Variable Rate(4):
2004A		October 2013	$	45,600		$	45,600
1985A		July 2015		100,000			100,000
1988A		December 2023		69,800			69,800
1985B&C		December 2025		75,000			75,000
1986A		December 2026		50,000			50,000
1987A		March 2027		25,760			25,760
1987B		July 2027		93,200			93,200
1991A		July 2029		115,705			115,705
Total Pollution Control Revenue Bonds				575,065			575,065
Notes Payable to Holdings(3)
5.80%		November 2012		500,000			500,000
3.83%		June 2010		350,000			350,000
3.72%		July 2009		350,000			350,000
Total Notes Payable to Holdings				1,200,000			1,200,000
Unamortized discount				(1,131	)		(1,496	)
Total Long-Term Debt				2,923,934			3,473,989
Less long-term debt due within one year				275,000			550,420
Long-Term Debt due after one year			$	2,648,934		$	2,923,569

(1)	Not callable prior to maturity.
(2)	Fixed rate pollution control revenue bonds first callable November 1, 2008 at 102%.
(3)	Currently callable with make-whole provisions.
(4)	Currently callable at par.
(5)	Effective interest rate at March 31, 2006 and March 31, 2005 was 3.24% and 2.33%, respectively.

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Substantially all of the Company’s operating properties are subject to mortgage liens securing its mortgage debt. Several series of First Mortgage Bonds were issued to secure a like amount of tax-exempt revenue bonds issued by the New York State Energy Research and Development Authority (NYSERDA). Approximately $575 million of such securities bear interest at short-term adjustable interest rates (with an option to convert to other rates, including a fixed interest rate) which averaged 3.20% for the year ended March 31, 2006, 1.69% for the year ended March 31, 2005 and 1.24% for the year ended March 31, 2004. The bonds are currently in the auction rate mode and are backed by bond insurance. Pursuant to agreements between NYSERDA and the Company, proceeds from such issues were used for the purpose of financing the construction of certain pollution control facilities at the Company’s generation facilities (which the Company subsequently sold) or to refund outstanding tax-exempt bonds and notes.

The aggregate maturities of long-term debt for the five years subsequent to March 31, 2006, excluding capital leases, are approximately:

(in millions of dollars)
Fiscal Year	Amount
2007	$	275
2008		200
2009		600
2010		350
2011		350
Thereafter		1,150
Total	$	2,925

The current portion of capital lease obligations is reflected in the other current liabilities line item on the Consolidated Balance Sheet and was approximately $1 million at March 31, 2006 and 2005. The non-current portion of capital lease obligations is reflected in the “Other” line item on the Consolidated Balance Sheet and was approximately $4 million and $5 million at March 31, 2006 and 2005, respectively.

At March 31, 2006 and 2005, the Company’s long-term debt, excluding intercompany debt, had a fair value of approximately $1.8 billion and $2.4 billion, respectively. The fair market value of the Company’s long-term debt was estimated based on the debts’ coupons and remaining lives along with the current interest rate conditions.

NOTE F — SHORT-TERM DEBT

The Company has regulatory approval from the FERC to issue up to $1 billion of short-term debt. The Company had short-term debt outstanding of $579 million and $401 million at March 31, 2006 and 2005, respectively, from affiliated companies. The Company participates with National Grid, and certain other National Grid affiliates, in a system money pool. The money pool is administered by the Service Company as the agent for the participants. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowings from the money pool bear interest at the higher of (i) the monthly average of the rate for high-grade, 30-day commercial paper sold through dealers by major corporations as published in The Wall Street Journal, or (ii) the monthly average of the

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rate then available to money pool depositors from an eligible investment in readily marketable money market funds or the existing short-term investment accounts maintained by money pool depositors or the Service Company during the period in question. In the event neither rate is one that is permissible for a transaction because of constraints imposed by the state regulatory commission having jurisdiction over a utility participating in the transaction, the rate is that which is permissible for the transaction as determined under the requirements of the state regulatory commission. Companies that invest in the money pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the money pool at any time without prior notice. The average interest rate for the money pool was 4.03%, 1.80 % and 1.11 % for fiscal years 2006, 2005 and 2004, respectively.

The Company had no short-term debt outstanding to third-parties at March 31, 2006 or 2005.

NOTE G — FEDERAL AND STATE INCOME TAXES

Following is a summary of the components of federal and state income tax and a reconciliation between the amount of federal income tax expense reported in the Consolidated Statements of Operations and the computed amount at the statutory tax rate:

	Year Ended March 31,
(in thousands of dollars)	2006			2005			2004
Components of federal and state income taxes:
Current tax expense (benefit):
Federal	$	61,211		$	(30,229	)	$	(12,003	)
State		22,509			9,459			(474	)
		83,720			(20,770	)		(12,477	)
Deferred tax expense:
Federal		89,908			177,180			128,426
State		13,566			3,542			20,022
		103,474			180,722			148,448
Total	$	187,194		$	159,952		$	135,971
Total income taxes in the consolidated statements of operations:
Income taxes charged to operations	$	190,194		$	171,230		$	138,843
Income taxes credited to “Other income (deductions)”		(3,000	)		(11,278	)		(2,872	)
Total	$	187,194		$	159,952		$	135,971

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Shown below is the reconciliation between federal income taxes and the tax computed at prevailing U.S. statutory rate on income before income taxes:

	Year Ended March 31,
(in thousands of dollars)	2006			2005			2004
Computed tax	$	176,495		$	148,371		$	96,481
Increase (reduction) including those attributable to flow-through of certain tax adjustments:
Depreciation		10,225			16,982			21,397
Cost of removal		(7,298	)		(5,664	)		(6,857	)
Allowance for funds used during construction — (a)		—			(1	)		3
State income taxes		23,449			8,451			12,736
Accrual to return adjustment		(9,410	)		3,427			19,842
Debt premium and mortgage recording tax		3,298			487			(1,556	)
E.S.O.P. dividends		—			(1,307	)		—
Dividends exclusion — federal income tax returns		(148	)		(174	)		(149	)
Provided at other than statutory rate		—			(1	)		(2	)
Medicare Act		(7,489	)		(3,579	)		—
Subsidiaries		—			136			250
Deferred investment tax credit reversal		(2,866	)		(2,866	)		(2,872	)
Other		938			(4,310	)		(3,302	)
Total		10,699			11,581			39,490
Federal and state income taxes	$	187,194		$	159,952		$	135,971

(a) Includes Carrying Charges (Interest Expense) imposed by the PSC.

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The deferred tax liabilities (assets) were comprised of the following:

as at March 31 (in thousands of dollars)	2006			2005
Alternative minimum tax	$	117,618		$	111,609
Unbilled revenues		26,205			23,458
Non-utilized NOL carryforward		—			105,212
Liability for environmental costs		191,307			198,621
Voluntary early retirement program		42,089			47,558
Bad debts		52,498			29,474
Pension and other post-retirement benefits		248,446			185,324
Other		268,092			209,550
Total deferred tax assets		946,255			910,806
Depreciation related		(979,936	)		(921,928	)
Investment tax credit related		(37,811	)		(40,677	)
Deferred environmental restoration costs		(186,842	)		(200,175	)
Merger rate plan stranded costs		(795,184	)		(848,182	)
Merger fair value pension and OPEB adjustment		(109,478	)		(128,188	)
Bond redemption and debt discount		(30,009	)		(25,056	)
Pension and other post-retirement benefits		(50,832	)		(88,830	)
Other		(275,169	)		(61,969	)
Total deferred tax liabilities		(2,465,261	)		(2,315,005	)
Net accumulated deferred income tax liability		(1,519,006	)		(1,404,199	)
Current portion (net deferred tax asset)		168,354			307,431
Net accumulated deferred income tax liability (non-current)	$	(1,687,360	)	$	(1,711,630	)

The Company has been audited and reported on by the Internal Revenue Service (IRS) through January 31, 2002.

The Company and other related subsidiaries of National Grid USA have participated with National Grid Holdings, Inc. (NGHI), a wholly owned subsidiary of National Grid plc, in filing consolidated US federal income tax returns since joining the NGHI consolidated filing group upon the Company’s January 31, 2002 acquisition by National Grid. The Company’s tax provisions and tax accounts are calculated on a separate company basis. Federal income tax returns have been examined and all appeals and issues have been agreed upon by the Internal Revenue Service (IRS) and the Company through January 31, 2002, the acquisition date and final tax return year end date of the Company’s former consolidated filing group prior to its acquisition by National Grid. In addition, federal income tax returns have been examined and all appeals and issues have been agreed upon by the IRS and the NGHI consolidated filing group through March 22, 2000. The IRS is currently reviewing the March 31, 2001 and March 31, 2002 tax returns of the NGHI consolidated filing group which the Company joined upon its acquisition. The IRS has issued a preliminary notice of deficiency disallowing certain tax deductions taken in these consolidated US federal income tax returns. These adjustments are being appealed. The Company has joint and several liability for any potential assessments against the consolidated group, for periods since it joined the group in February 2002. Management believes that the positions taken by the Company and its related subsidiaries and parent company are appropriate and the resolution of the tax matters will not have a material effect on the Company’s financial position, results of operations or cash flows.

In December 1998, the Company received a ruling from the IRS which provided that the amount of cash and the value of common stock that was paid by the Company to the subject terminated IPP Parties was deductible in 1998 which resulted in the Company not paying any regular federal

45

income taxes for 1998, and further generated a substantial net operating loss for federal income tax purposes. The Company carried back a portion of the unused net operating loss (NOL) to the years 1996 and 1997, and also for the years 1988 through 1990, which resulted in federal income tax refunds of $135 million that were received in January 1999. As a result of the merger with National Grid, the Company is now part of the consolidated tax return filing group of National Grid Holdings, Inc. The consolidated tax filing group was able to utilize the remaining NOL carryforward, which was $301 million as of March 31, 2006, in the 2005 fiscal year. National Grid’s ability to utilize the NOL carryforward generated as a result of the MRA and the utilization of alternative minimum tax credits is affected by the rules of Section 382 of the Internal Revenue Code.

There were no valuation allowances for deferred tax assets at March 31, 2006 or 2005.

NOTE H — EMPLOYEE BENEFITS

Summary

The Company has a non-contributory defined benefit pension plan covering substantially all employees. The pension plan is a cash balance pension plan design and under that design, pay-based credits are applied based on service time, and interest credits are applied based on an average annual 30-year Treasury bond yield. In addition, a large number of employees hired by the Company prior to July 1998 are cash balance design participants who receive a larger benefit if so yielded under pre-cash balance conversion final average pay formula provisions. Employees hired by the Company following the August 1998 cash balance design conversion participate under cash balance design provisions only.

A supplemental nonqualified, non-contributory executive retirement program provides additional defined pension benefits for certain executives.

The Company provides post-retirement benefits other than pensions (PBOPs). PBOPs include health care and life insurance coverage to eligible retired employees. Eligibility is based on certain age and length of service requirements and in some cases retirees must contribute to the cost of their coverage.

Governed by the PSC’s “Statement of Policy Concerning the Accounting and Ratemaking Treatment for Pensions and Postretirement Benefits Other than Pensions” (SOP), the SOP dictates the accounting policy for the plans and requires amortization of unrecognized prior service costs and unrecognized gains and losses over a 10-year period calculated on a vintage year basis.

Funding Policy

Funding policy is determined largely by the Company’s settlement agreements with the PSC and what is recovered in rates. However, the contribution for any year will not be less than the minimum contribution required by federal law or greater than the maximum tax-deductible amount.

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Plan Assets

The target asset allocations for the benefit plans are:

	Pension Benefits						Non-Union PBOPs						Union PBOPs
	2006			2005			2006			2005			2006			2005
U.S. equities		42	%		47	%		30	%		50	%		49	%		45	%
Global equities (including U.S.)		6	%		7	%		—			—			—			—
Non-U.S. equities		12	%		11	%		20	%		5	%		21	%		15	%
Fixed income		35	%		35	%		50	%		45	%		30	%		40	%
Private equity and property		5	%		—			—			—			—			—
		100	%		100	%		100	%		100	%		100	%		100	%

The percentage of the fair value of total plan assets at March 31:

	Pension Benefits						Non-Union PBOPs						Union PBOPs
	2006			2005			2006			2005			2006			2005
U.S. equities		46	%		46	%		29	%		54	%		50	%		52	%
Global equities (including U.S.)		8	%		8	%		—			—			—			—
Non-U.S. equities		13	%		12	%		20	%		5	%		22	%		16	%
Fixed income		33	%		34	%		51	%		41	%		28	%		32	%
Private equity and property		—			—			—			—			—			—
		100	%		100	%		100	%		100	%		100	%		100	%

The Company manages benefit plan investments to minimize the long-term cost of operating the Plans, with a reasonable level of risk. Risk tolerance is determined as a result of a periodic asset/liability study which analyzes plan liabilities and plan funded status and results in the determination of the allocation of assets across equity and fixed income securities. Equity investments are broadly diversified across U.S. and non-U.S. stocks, as well as across growth, value, and small and large capitalization stocks. Likewise, the fixed income portfolio is broadly diversified across the various fixed income market segments. Small investments are also held in private equity, with the objective of enhancing long-term returns while improving portfolio diversification. For the PBOP plan, since the earnings on a portion of the assets are taxable, those investments are managed to maximize after tax returns consistent with the broad asset class parameters established by the asset allocation study. Investment risk and return is reviewed by the investment committee on a quarterly basis.

The estimated rate of return for various passive asset classes is based both on analysis of historical rates of return and forward looking analysis of risk premiums and yields. Current market conditions, such as inflation and interest rates, are evaluated in connection with the setting of the long-term assumption. A small premium is added for active management of both equity and fixed income. The rates of return for each asset class are then weighted in accordance with the target asset allocation, and the resulting long-term return on asset rate is then applied to the market-related value of assets.

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Assumptions used for Benefits Accounting

The following weighted average assumptions were used to determine the pension and PBOP benefit obligations and net periodic costs for the fiscal years ending March 31.

	Pension Benefits						PBOP
	2006			2005			2006			2005
Benefit obligations
Discount rate		6.00	%		5.75	%		6.00	%		5.75	%
Rate of compensation increase		3.90	%		3.90	%		n/a			n/a
Expected long-term rate of return		8.00	%		8.25	%		7.81	%		8.21	%
Health care cost trend rate
Initial		n/a			n/a			n/a			10.00	%
Pre 65*		n/a			n/a			10.00	%		n/a
Post 65*		n/a			n/a			11.00	%		n/a
Ultimate		n/a			n/a			5.00	%		5.00	%
Year ultimate rate is reached		n/a			n/a			n/a			2010
Pre 65*		n/a			n/a			2011			n/a
Post 65*		n/a			n/a			2012			n/a

* In fiscal year 2006, the health care cost trend assumption was updated to include rates for the pre 65 and post 65 age groups.

	Pension Benefits									PBOP
	2006			2005			2004			2006			2005			2004
Net periodic benefit cost
Discount rate		5.75	%		5.75	%		6.25	%		5.75	%		5.75	%		6.25	%
Rate of compensation increase		3.90	%		3.25	%		3.25	%		n/a			n/a			n/a
Expected long-term rate of return		8.25	%		8.50	%		8.50	%		8.16	%		8.26	%		8.00	%
Health care cost trend rate
Initial		n/a			n/a			n/a			10.00	%		10.00	%		10.00	%
Ultimate		n/a			n/a			n/a			5.00	%		5.00	%		5.00	%
Year ultimate rate reached		n/a			n/a			n/a			2010			2009			2008

The expected contributions to the Company’s pension and PBOP plans during fiscal year 2007 are approximately $75 million and $81 million, respectively.

For the calculation of fiscal year 2007 pension and PBOP expense, the expected long-term rates of return on plan assets will be changed to 8% for the qualified pension plan, 7% for the nonunion PBOP plan, and 8% for the union PBOP plan.

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Pension Benefits

The Company’s net periodic benefit cost for the years ended March 31, 2006, 2005 and 2004 included the following components:

(in thousands of dollars)	2006			2005			2004
Service cost	$	32,483		$	29,324		$	28,093
Interest cost		75,370			71,014			74,863
Expected return on plan assets		(67,431	)		(67,787	)		(71,391	)
Amortization of unrecognized prior service cost		3,454			1,851			1,160
Amortization of unrecognized loss		34,268			26,269			18,026
Net periodic benefit costs before settlement / curtailments		78,144			60,671			50,751
Special termination benefits		—			—			14,300
Settlement and curtailment loss		—			185			21,798
Net periodic benefit costs	$	78,144		$	60,856		$	86,849

The following table provides a reconciliation of the plans’ fair value of assets for the fiscal years 2006 and 2005.

(in thousands of dollars)	2006			2005
Fair value of plan assets at beginning of period	$	830,469		$	845,900
Actual return on plan assets		107,337			52,246
Company contributions		76,181			81,730
Benefits paid		(110,411	)		(148,350	)
Settlements		—			(1,057	)
Fair value of plan assets at end of period	$	903,576		$	830,469

The following table provides the changes in the Company’s pension plans’ benefit obligations, reconciliation of the benefit obligation, funded status and the amounts recognized in the balance sheet at March 31:

(in thousands of dollars)	2006			2005
Accumulated benefit obligation	$	1,218,180		$	1,265,181
Benefit obligation at beginning of period	$	1,379,059		$	1,298,548
Service cost		32,483			29,324
Interest cost		75,370			71,014
Actuarial (gain) loss		(35,141	)		98,380
Plan amendments		—			31,201
Benefits paid		(110,411	)		(148,350	)
Settlements		—			(1,058	)
Benefit obligation at end of period	$	1,341,360		$	1,379,059

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(in thousands of dollars)	2006			2005
Funded status	$	(437,784	)	$	(548,590	)
Unrecognized actuarial loss		200,422			309,737
Unrecognized prior service cost		36,885			40,339
Net amount recognized on the balance sheet	$	(200,477	)	$	(198,514	)

(in thousands of dollars)	2006			2005
Amounts recognized on the balance sheet consist of:
Employee pension liability	$	(314,604	)	$	(434,712	)
Intangible asset		36,885			40,339
Regulatory assets		75,252			194,302
Accumulated other comprehensive income, before taxes		1,990			1,557
Net amount recognized	$	(200,477	)	$	(198,514	)

The following pension benefit payments, which reflect expected future services, as appropriate, are expected to be paid from the Company’s pension plans:

(in millions of dollars)	Pension Benefits
2007		$	108
2008		$	110
2009		$	111
2010		$	115
2011		$	120
2012-2016		$	639

Additional Minimum Pension Liability

The Company has recorded an additional minimum pension liability of approximately $114 million and $236 million at March 31, 2006 and 2005, respectively, for its pension plans because the pension plans’ accumulated benefit obligation was in excess of the accrued pension liability on the balance sheet. While the offset to this entry would normally be an after-tax charge to other comprehensive income, due to the nature of its rate plan, the Company has instead recorded a pre-tax regulatory asset.

Defined contribution plan

The Company also has a defined contribution pension plan (employee savings fund plan) that covers substantially all employees. Employer matching contributions of approximately $7 million were expensed for the each of the fiscal years ended March 31, 2006, 2005 and 2004.

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Postretirement Benefit Plans Other than Pensions: The Company’s total cost of PBOPs for the fiscal years ended March 31, 2006, 2005 and 2004 included the following components:

(in thousands of dollars)	2006			2005			2004
Service cost	$	18,887		$	13,160		$	8,629
Interest cost		70,519			62,887			57,952
Expected return on plan assets		(45,819	)		(45,798	)		(34,578	)
Amortization of unrecognized prior service cost		14,568			5,915			—
Amortization of unrecognized net loss		30,516			24,310			22,996
Special termination benefits		—			—			641
Net periodic benefit costs	$	88,671		$	60,474		$	55,640

The following table provides a reconciliation of the PBOP plans’ fair value of assets for the fiscal years ended March 31, 2006 and 2005.

(in thousands of dollars)	2006			2005
Fair value of plan assets at beginning of period	$	589,917		$	589,478
Actual return on plan assets during year		69,721			31,836
Company contributions		19,700			27,600
Benefits paid from plan assets		(62,708	)		(58,997	)
Fair value of plan assets at end of period	$	616,630		$	589,917

The following tables provide the reconciliation of the benefit obligation and the funded status of the PBOP plans at March 31:

(in thousands of dollars)	2006			2005
Benefit obligation at beginning of period	$	1,268,233		$	1,059,003
Service cost		18,887			13,160
Interest cost		70,519			62,887
Actuarial loss		33,745			39,897
Plan amendments		—			152,967
Benefits paid		(65,651	)		(59,681	)
Benefit obligation at end of period	$	1,325,733		$	1,268,233

(in thousands of dollars)	2006			2005
Funded status	$	(709,103	)	$	(678,317	)
Unrecognized prior service cost		132,484			147,052
Unrecognized actuarial loss		247,986			268,659
Net amount recognized	$	(328,633	)	$	(262,606	)

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As a result of the Medicare Act of 2003, the Company receives a federal subsidy for sponsoring a retiree healthcare plan that provides a benefit that is actuarially equivalent to Medicare Part D. The following PBOP benefit payments and subsidies, which reflect expected future service, as appropriate, are expected to be paid and received:

(in millions of dollars)	Payments		Subsidies
2007	$	68	$	4
2008	$	71	$	4
2009	$	74	$	5
2010	$	77	$	5
2011	$	80	$	5
2012-2016	$	392	$	28

A one-percentage point change in assumed health care cost trend rates would have the following effects:

(in thousands of dollars)	2006			2005
Increase 1%
Total of service cost plus interest cost	$	17,330		$	13,985
Post-retirement benefit obligation	$	215,617		$	196,034
Decrease 1%
Total of service cost plus interest cost	$	(14,329	)	$	(11,629	)
Post-retirement benefit obligation	$	(185,317	)	$	(169,719	)

Settlement Losses

Under SFAS No. 88 “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” the Company must recognize a portion of unrecognized gains or losses immediately when payouts from the plans exceed a certain amount. The Company recognized a loss of approximately $22 million in fiscal 2004 relating to the re-measurement of the benefit plans from the voluntary early retirement offer.

In July 2004, the Company obtained PSC approval that would provide rate recovery for approximately $14 million of the $30 million pension settlement loss incurred in fiscal 2003. In addition, the agreement covers the funding of the entire settlement loss to benefit plan trust funds. The Company has filed a petition with the PSC seeking recovery of a $22 million pension settlement loss incurred in fiscal year 2004.

Regulatory treatment of pensions and PBOP plans

In addition to the regulatory assets established in connection with purchase accounting and the additional minimum pension liability discussed above, the regulatory asset account “Pension and post-retirement benefit plans” includes certain other components. First, the Company is required under the Merger Rate Plan to defer the difference between pension and post-retirement benefit expense and the allowance in rates for these costs. Also, the regulatory asset account includes the unamortized portion of the merger related early retirement program costs, a post-retirement benefit phase-in deferral established in the mid-1990’s, and the offset to the additional minimum pension liability discussed above. The merger related early retirement program costs are being amortized unevenly over the 10 years of the Merger Rate Plan with larger amounts being amortized in the earlier years. This amortization in fiscal 2006 and 2005 was approximately $4

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million and $7 million, respectively. The phase-in deferral is being amortized at a rate of approximately $3 million per year.

NOTE I — PREFERRED STOCK

The Company has certain issues of non-participating preferred stock which provide for redemption at the option of the Company, as shown in the table below. From time to time, the Company repurchases shares of its preferred stock when it is approached on behalf of its shareholders.

									Redemption price
	Shares				(in thousands of dollars)				per share
	March 31,		March 31,		March 31,		March 31,		(Before adding
Series	2006		2005		2006		2005		accumulated dividends)
Preferred $100 par value:
3.40%		57,536		57,536	$	5,754	$	5,754	$	103.50
3.60%		137,139		137,139		13,714		13,714		104.85
3.90%		94,967		94,967		9,496		9,496		106.00
4.10%		52,830		52,830		5,283		5,283		102.00
4.85%		35,128		35,128		3,513		3,513		102.00
5.25%		34,115		34,115		3,410		3,410		102.00
Total preferred stock		411,715		411,715	$	41,170	$	41,170

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NOTE J — SEGMENTS

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 electricity-transmission, electricity-distribution, and gas-distribution. Certain information regarding the Company’s segments is set forth in the following tables. Corporate assets consist primarily of other property and investments, cash, restricted cash, current deferred income taxes and unamortized debt expense. General corporate expenses, property common to the various segments, and depreciation of such common property have been 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.

			Electricity-Distribution
					Electricity -		Total
	Electricity -		Electricity –		Stranded Cost		Electricity-		Gas –
(in millions of dollars)	Transmission		Distribution		Recoveries		Distribution		Distribution		Corporate		Total
Year ended March 31, 2006
Operating revenue	$	261	$	2,550	$	496	$	3,046	$	1,037	$	—	$	4,344
Operating income before income taxes		105		346		184		530		105		—		740
Depreciation and amortization		35		131		—		131		38		—		204
Amortization of stranded costs		—		—		267		267		—		—		267
Year ended March 31, 2005
Operating revenue	$	255	$	2,376	$	486	$	2,862	$	808	$	—	$	3,925
Operating income before income taxes		105		286		176		462		105		—		672
Depreciation and amortization		35		129		—		129		37		—		201
Amortization of stranded costs		—		—		251		251		—		—		251
Year ended March 31, 2004
Operating revenue	$	255	$	2,457	$	572	$	3,029	$	780	$	—	$	4,064
Operating income before income taxes		93		234		183		417		68		—		578
Depreciation and amortization		35		130		—		130		36		—		201
Amortization of stranded costs		—		—		194		194		—		—		194

			Electricity-Distribution
						Electricity -		Total
	Electricity -		Electricity –			Stranded Cost		Electricity -			Gas –
	Transmission		Distribution			Recoveries		Distribution			Distribution		Corporate		Total
Goodwill
Goodwill, at March 31, 2005	$	303	$	706		$	—	$	706		$	215	$	—	$	1,224
Change in goodwill		—		(9	)		—		(9	)		—		—		(9	)
Goodwill, at March 31, 2006	$	303	$	697		$	—	$	697		$	215	$	—	$	1,215
Total Assets
At March 31, 2006	$	1,595	$	5,302		$	3,051	$	8,353		$	1,931	$	402	$	12,281
At March 31, 2005	$	1,557	$	5,193		$	3,402	$	8,595		$	1,819	$	547	$	12,518

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NOTE K — STOCK BASED COMPENSATION

Prior to the Company’s merger with National Grid, stock appreciation rights (SARs) tied to the price of Holdings’ share price were granted to officers, key employees and directors. The table below sets forth the activity under the SARs program for the periods March 31, 2004 through March 31, 2006. Since SARs are payable in cash, the accounting under APB No. 25 and SFAS No. 123R is the same.

	SARs
	Shares
Outstanding at March 31, 2004		341,268
Exercised		(93,146	)
Outstanding at March 31, 2005		248,122
Exercised		(87,680	)
Outstanding at March 31, 2006		160,442

The Company’s SARs program provided for the acceleration of vesting upon the occurrence of certain events relating to a change in control, merger, sale of assets or liquidation of the Company. On January 31, 2002, the acquisition of Holdings’ by National Grid was completed and outstanding Holdings’ SARs were converted to National Grid Group plc American Depositary Share (ADS) SARs. The SARs are payable in cash based on the increase in the ADS price from a specified level. As such, for these awards, compensation expense is recognized based on the value of the ADS price of National Grid Group plc over the vesting period of the award.

Included in the Company’s results of operations for years ended March 31, 2006 and 2005, is approximately $1 million of expense for each year related to the SARs program.

NOTE L — DERIVATIVES AND HEDGING ACTIVITIES

In the normal course of business, the Company is party to derivative financial instruments (derivatives) that are principally used to manage commodity prices associated with its natural gas and electric operations. These financial exposures are monitored and managed as an integral part of the Company’s overall Financial Risk Management Policy. At the core of the policy is a condition that the Company will engage in activities at risk only to the extent that those activities fall within commodities and financial markets to which it has a physical market exposure in terms and volumes consistent with its core business. The Company does not issue or intend to hold derivative instruments for speculative trading purposes. Derivatives are accounted for in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” which requires derivatives to be reported at fair value as assets or liabilities on the balance sheet. The change in fair value of instruments that qualify for hedge accounting are deferred in Accumulated Other Comprehensive Income and will be reclassified through purchased electricity or purchased gas expense within the next twelve months. Other instruments are deferred in regulatory assets or liabilities according to current rate agreements and are reclassified through purchased electricity or gas expense in the hedge months. The Company’s rate agreements allow for the pass-through of the commodity costs of electricity and natural gas, including the costs of the hedging programs.

The Company has eight indexed swap contracts, expiring in fiscal year 2009 (June 2008), that resulted from the MRA. These derivatives are not designated as hedging instruments and are

55

covered by regulatory rulings that allow the gains and losses to be recorded as regulatory assets or regulatory liabilities. As of March 31, 2006 and 2005, the Company had recorded liabilities at net present value of $537 million and $619 million, respectively, for these swap contracts and had recorded a corresponding swap contracts regulatory asset. The asset and liability are amortized over the remaining term of the swaps as nominal energy quantities are settled and they are adjusted as periodic reassessments are made of energy price forecasts.

At March 31, 2006, the Company projects that it will make the following payments in connection with its swap contracts for the fiscal years 2007 through 2009, subject to changes in market prices and indexing provisions:

	Projected
	Payment
Year Ended	(in thousands
March 31,	of dollars)
2007	$	246,551
2008		246,173
2009		44,729
Thereafter		—
Total	$	537,453

The Company uses New York Mercantile Exchange (NYMEX) gas futures to hedge the gas commodity component of its indexed swap contracts. These instruments, as used, do not qualify for hedge accounting status under SFAS No. 133. Cash flow hedges that qualify under SFAS No. 133 are as follows: NYMEX gas futures for the purchases of natural gas and NYMEX electric swap contracts hedging the purchases of electricity.

The following table represents the open positions at March 31, 2006 and the results on operations of these instruments for the year ended March 31, 2006.

(In thousands of dollars)				Balances as of March 31, 2006
												Year Ended
									Accumulated			March 31, 2006
						Accumulated			Deferred			Gain/(Loss)
				Regulatory		OCI** ,			Income Tax			Reclass to
Derivative Instrument	Asset*			Deferral		net of tax			on OCI**			Commodity Costs
Qualified for Hedge Accounting
NYMEX futures — gas supply	$	(5,358.8	)	$	—	$	4,943.0		$	(3,296.0	)	$	35,956.6
NYMEX electric swaps — electric supply	$	317.5		$	—	$	(190.5	)	$	127.0		$	3,260.2
Non-Qualified for Hedge Accounting
NYMEX futures — IPP swaps/non-MRA IPP	$	(27,195.9	)	$	31,718.1	$	—		$	—		$	59,464.9

*	Differences between asset and regulatory or other comprehensive income deferral represent contracts settled for the following month.
**	Other Comprehensive Income (OCI)

At March 31, 2005, the Company in part recorded a deferred gain on the futures contracts hedging the IPP swaps and non-MRA IPP of $30 million, which partially offset the consolidated balance sheet item “Derivative instruments” for $27 million, with the resulting $3 million having

56

settled through cash for the hedge month of April 2005. For the twelve months ended March 31, 2005, settlement of NYMEX futures contracts resulted in a decrease to purchased power expense of $19 million.

The gains and losses on the derivatives that are deferred and reported in accumulated other comprehensive income will be reclassified as purchased energy expense in the periods in which expense is impacted by the variability of the cash flows of the hedged item. For the twelve months ended March 31, 2006, the realized net gain of $36 million from hedging instruments, as shown in the table above, was recorded to gas purchases and was offset by a corresponding increase in the cost of a comparable amount of gas. For the twelve months ended March 31, 2005, a realized net gain of $8 million was recorded to gas purchases and was offset by a corresponding decrease in the cost of a comparable amount of gas.

The actual amounts to be recorded in purchased energy expense are dependent on future changes in the contract values. The majority of these deferred amounts will be reclassified to expense within the next twelve months. A nominal amount of the hedging instruments extend into April 2007. There were no gains or losses recorded during the fiscal year ended March 31, 2006 from the discontinuance of gas futures or electric swap cash flow hedges.

At March 31, 2006, the deferred gain on NYMEX electric swap contracts to hedge electricity purchases was $0.3 million. There were no open electric swaps at March 31, 2005.

NOTE M — RESTRICTION ON COMMON DIVIDENDS

The indenture securing the Company’s mortgage debt provides that retained earnings shall be reserved and held unavailable for the payment of dividends on common stock to the extent that expenditures for maintenance and repairs plus provisions for depreciation do not exceed 2.25% of depreciable property as defined therein. These provisions have never resulted in a restriction of the Company’s retained earnings.

The Company is limited by the Merger Rate Plan and under FERC and SEC orders with respect to the amount of dividends it can make to Holdings. As long as the Company remains rated Investment Grade, it is allowed to make dividends in an amount up to the pre-merger retained earnings balance plus any earnings subsequent to the merger, together with other adjustments that are authorized under the Merger Rate Plan and other regulatory orders.

NOTE N — COST OF REMOVAL AND ASSET RETIREMENT OBLIGATION

In 2001, FASB issued SFAS No. 143. SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. The Company was required to adopt SFAS No. 143 as of April 1, 2003. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation under existing or enacted law, statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.

Under the Company’s current and prior rate plans it has collected through rates an implied cost of removal for its plant assets. This cost of removal collected from customers differs from the SFAS No. 143 definition of an asset retirement obligation in that these collections are for costs to remove an asset when it is no longer deemed usable (i.e. it is broken or obsolete) and not necessarily from a legal obligation. For a vast majority of its electric and gas transmission and

57

distribution assets, the Company would use these funds to remove the asset so a new one could be installed in its place.

The cost of removal collections from customers has historically been embedded within accumulated depreciation (as these costs have been charged over time through depreciation expense). With the adoption of SFAS No. 143, the Company has reclassified these cost of removal collections to a regulatory liability account to more properly reflect the future usage of these collections. The Company estimates it has collected over time approximately $338 million and $318 million for cost of removal through March 31, 2006 and 2005, respectively.

In March 2005, the FASB issued FIN 47 that clarifies that the term ‘conditional asset retirement obligation’ used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the Company. This statement is effective for the Company for its fiscal year ended March 31, 2006. The Company has a $10 million asset retirement obligation reserve as of March 31, 2006 which does not have a material impact on the Company’s results of operations or financial position.

NOTE O — QUARTERLY FINANCIAL DATA (UNAUDITED)

Operating revenues, operating income, and net income by quarter from April 1, 2004 through March 31, 2006 are shown in the following table. The Company believes it has included all adjustments necessary for a fair presentation of the results of operations for the quarters. Due to the seasonal nature of the regulated utility business, the annual amounts are not generated evenly by quarter during the year. The Company’s quarterly results of operations reflect the seasonal nature of its business, with peak electric loads in summer and winter periods. Gas sales peak in the winter. The Company’s consolidated financial statements for the fiscal year ended March 31, 2006 included out-of-period adjustments. The out-of-period adjustments had a positive impact of $7 million on reported net income for the fiscal year ended March 31, 2006 and an offsetting negative impact on several prior fiscal years. The adjustments were recorded in fiscal year 2006 because they did not meet the materiality threshold for prior period restatement.

		(In thousands of dollars)
		Operating		Operating		Net
Quarter Ended		Revenues		Income		Income
March 31,	2006	$	1,294,825	$	179,746	$	120,172
	2005		1,215,027		164,521		116,679
December 31,	2005		1,109,285		119,502		63,304
	2004		907,037		116,611		55,517
September 30,	2005		981,081		131,043		76,251
	2004		912,868		114,948		50,218
June 30,	2005		958,832		119,385		57,349
	2004		890,239		104,614		40,835

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

There is no disagreement or reportable event required to be reported under this Item 9.

ITEM 9A. 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 and as of that evaluation, it was determined that these disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in reports that the Company files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required.

During the most recent fiscal quarter, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following table lists the Company’s executive officers and directors:

Name	Age		Position
William F. Edwards		49	President and Director
John G. Cochrane		48	Chief Financial Officer
Joseph T. Ash, Jr.		57	Vice President, Energy Supply, Pricing and Regulatory Proceedings
Paul J. Bailey		48	Controller
Barbara A. Hassan		56	Senior Vice President and Director
Michael E. Jesanis		49	President and Chief Executive Officer of National Grid USA and Director
Michael J. Kelleher		48	Senior Vice President, Business Services, and Director
Clement E. Nadeau		54	Senior Vice President, Operations, and Director
Anthony C. Pini		53	Senior Vice President, Customer Service, and Director
Cheryl A. LaFleur		51	Executive Vice President, Chief Operating Officer of National Grid USA, and Director
Lawrence J. Reilly		50	Executive Vice President and General Counsel of National Grid USA
Masheed H. Saidi		51	Vice President, and Senior Vice President, Transmission, National Grid USA Service Company, Inc.
Steven W. Tasker		48	Senior Vice President and Treasurer

Directors are elected at the annual meeting of stockholders and hold office until the next annual meeting or a special meeting in lieu thereof, and until their successors are elected and qualified. There are no family relationships between any of the directors and executive officers listed in the table. There are no arrangements or understandings between any executive officer and any other person pursuant to which he or she was selected as an officer.

Mr. Edwards was elected President of the Company and appointed a director effective January 31, 2002. Prior to that, he served as Senior Vice President and Chief Financial Officer of the Company from 1997 to 2002. He served as Senior Vice President and Chief Financial Officer of Niagara Mohawk Holdings, Inc. from 1999 to 2002. He also serves as an Executive Vice President of National Grid USA Service Company and is a director of the Service Company and of National Grid USA.

Mr. Cochrane was elected Chief Financial Officer effective August 1, 2002. He has served as National Grid USA’s Chief Financial Officer since January 2001 and is its Treasurer, an Executive Senior Vice President and a director.

Mr. Ash has served as Vice President, Energy Supply, Pricing and Regulatory Proceedings since July 2003. He was Vice President, Gas Delivery, from December 1998 to April 2002.

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Mr. Bailey was elected Controller effective January 2006. He also serves as Controller of National Grid USA Service Company, Inc. Mr. Bailey was Vice President of Finance and Administration of Harvard Bioscience, Inc. from October 2003 until September 2005, when he joined National Grid. From 1998 to 2002, Mr. Bailey worked for Thermo Electron Corporation as the Controller of its analytical instruments business, formerly known as Thermo Instrument Systems, Inc.

Ms. Hassan was elected Senior Vice President and a director in April 2006. Since May 2000, she has served as Senior Vice President of the Company’s New England electricity distribution affiliates.

Mr. Jesanis was elected director of the Company in January 2002. He became President of National Grid USA in November 2003 having been its Chief Operating Officer and responsible for the day-to-day operations since January 2001. Mr. Jesanis is also a director of National Grid USA and an executive director of National Grid plc.

Mr. Kelleher was elected Senior Vice President of the Company effective May 1, 2004 and was elected a director in May 2006. He served as Vice President of National Grid USA from January 2002 to March 2004 and as its Treasurer from April 2002 to April 2003. Prior to that, he served as Vice President Financial Planning of Niagara Mohawk Power Corporation from 1999 to 2001.

Ms. LaFleur was elected director of the Company in April 2006. She also became Executive Vice President and Chief Operating Officer of National Grid USA in April 2006, having been a Senior Vice President since March 2000. She serves as a director of National Grid USA and the Company’s four New England electric distribution affiliates and was President of the four distribution affiliates from January 2001 until April 2006.

Mr. Nadeau was elected Senior Vice President and a director of the Company effective January 31, 2002. Prior to that, he served as Vice President-Electric Delivery beginning in 1998.

Mr. Pini was elected Senior Vice President of the Company effective January 31, 2002. Previously, he was President of NEES Communications, Inc. from 1997 to 2002 and Vice President of Retail Customer Service of National Grid USA subsidiaries from 1993 to 1997.

Mr. Reilly has been Secretary and General Counsel of National Grid USA since January 2001 and is a Director and Executive Vice President of National Grid USA.

Ms. Saidi has served as Vice President since November 2005, when she was also elected Senior Vice President of National Grid USA Service Company with responsibility for National Grid’s US transmission operations. From 1998 to 2004, Ms. Saidi was a Vice President of the Company’s transmission affiliate, New England Power Company, and from 2004 to 2005 she served as Senior Vice President and Chief Operating Officer of GridAmerica.

Mr. Tasker has served as Senior Vice President, Distribution Finance, and Treasurer since February 2002. He was Vice President and Controller from December 1998 to February 2002.

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Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s executive officers and directors, and persons who own more than 10 % of a registered class of the Company’s equity securities, to file reports with the Securities and Exchange Commission disclosing their ownership of stock in the Company and changes in such ownership. To the Company’s knowledge, based solely on written representations from reporting persons, no such reports were required to be filed during the fiscal year ended March 31, 2004.

Senior Financial Officer Code of Ethics

The Company has adopted a code of ethics that applies to its principal executive officer, principal financial officer and principal accounting officer. This code is available on the National Grid plc website, at www.nationalgrid.com, where any amendments or waivers will also be posted. There were no amendments to, or waivers under, the Company’s Code of Ethics in the fiscal year ended March 31, 2006.

The inclusion of National Grid plc’s website address in this annual report does not, and is not intended to, incorporate the contents of its website into this report and such information does not constitute part of this annual report.

ITEM 11. EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth the compensation paid or accrued for services rendered to Niagara Mohawk in the fiscal years ended March 31, 2006, 2005 and 2004 by the president and the four most highly paid persons who were serving as executive officers on March 31, 2006 (the Named Executive Officers).

					Annual Compensation (a)
							Other Annual
Name and Principal							Compensation		All Other Compensation
Position	Year		Salary($)		Bonus($)(b)		($)(c)		($)(d)(e)
William F. Edwards		2006		435,000		665,637		6,850		540
President		2005		420,000		266,410		3,675		540
		2004		399,994		210,000		7,000		270
John G. Cochrane (f)		2006		193,737		108,533		8,409		4,336
Chief Financial Officer		2005		166,900		110,001		7,300		3,876
		2004		146,181		99,044		5,276		2,952
Michael E. Jesanis (f)		2006		358,646		294,162		7,177		3,886
President & CEO, National		2005		259,534		203,511		3,686		2728
Grid USA		2004		225,015		146,390		6,773		2,682
Michael J. Kelleher Senior Vice President		2006		205,000		108,191		6,997		1,590
Business Services		2005		203,333		108,352		130,640		9,540
Clement E. Nadeau		2006		230,917		121,855		6,325		1,008
Senior Vice President		2005		218,750		151,091		6,150		828
Operations		2004		210,000		120,250		11,096		5,889

(a) Includes deferred compensation in category and year earned.

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(b)	The bonus figure represents cash bonuses and the fair market value of unrestricted securities of National Grid plc awarded under an incentive compensation plan and cash bonuses awarded under the all-employees goals program. For Mr. Edwards, it also includes a special cash bonus associated with the completion of certain corporate objectives.
(c)	Includes amounts reimbursed for the payment of taxes on certain non-cash benefits and contributions to the incentive thrift plan that are not bonus contributions.
(d)	Includes Company contributions to life insurance. Also includes the value of financial services provided to Messrs. Jesanis, Cochrane and Kelleher.
(e)	No options or stock appreciation rights were awarded in fiscal 2004, 2005 or 2006.
(f)	Messrs. Cochrane and Jesanis perform service for affiliate companies. Compensation that is allocable to Niagara Mohawk is set forth in the table.

Long-Term Incentive Plans — Awards in Last Fiscal Year

The following table sets forth awards made under the National Grid Performance Share Plan to the Named Executive Officers during fiscal 2006.

				Estimated Future Payouts
	Number of			Threshold		Maximum
Name	Shares (#)		Performance Period	(#)		(#)
William F. Edwards		4,481	July 1, 2005 through June 30, 2008		1,344		4,481
John G. Cochrane		4,574	July 1, 2005 through June 30, 2008		1,372		4,574
Michael E. Jesanis		21,634	July 1, 2005 through June 30, 2008		6,490		21,634
Michael J. Kelleher		2,122	July 1, 2005 through June 30, 2008		637		2,122
Clement E. Nadeau		2,880	July 1, 2005 through June 30, 2008		864		2,880

Under the National Grid Performance Share Plan, executives receive notional allocations of American Depositary Shares of National Grid. Shares vest after three years, subject to the satisfaction of the relevant performance criteria which are set at the date of grant and measured over a three-year period. Shares must then be held for a further year, after which they are released. For the grants set forth above, the relevant criteria are total shareholder return (TSR) performance and earnings per share (EPS) growth . Vesting of fifty percent of the award is subject to TSR performance relative to the TSR performance of companies in the FTSE 100. Vesting of the other fifty percent of the award is subject to National Grid EPS growth versus the UK inflation rate as measured by the UK Retail Price Index (RPI). The proportion of the original award of shares that will transfer to participants will depend on National Grid’s performance against each of these measurements. For the TSR criterion, National Grid must achieve median TSR ranking relative to TSR performance of the FTSE 100 companies in order for participants to realize the threshold payout of 30% of the original award. It must achieve more than 7.5 percentage point above median relative to the FTSE 100 companies for participants to achieve the maximum payout of 100% of the original award. For the EPS criterion, National Grid’s EPS must exceed RPI by a minimum of 3 percentage points to realize the threshold of 30% of the original award. To achieve the maximum payout, National Grid’s EPS must exceed RPI growth by 6 percentage points.

Option/SAR Exercises in Fiscal Year 2005 and Fiscal Year-End Option/SAR Values

The following table sets forth, for the Named Executive Officers, the number of shares for which stock options were exercised in fiscal year 2006, the realized value or spread (the difference

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between the exercise price and market value on the date of exercise) and the number and unrealized spread of the unexercised options held by each at fiscal year-end.

					Number of Securities
					Underlying Unexercised
					Options on March 31, 2006				Value of Unexercised Options
			Value		(#)				on March 31, 2006 ($)(a)(b)
	Options		Realized						Exercisable		Unexercisable
Name	Exercised (#)		($)		Exercisable		Unexercisable		(b)		(c)
William F. Edwards		0		0		56,206			$	88,997
John G. Cochrane		0		0		92,395		32,620	$	73,780		0
Michael E. Jesanis		0		0		143,960		51,169	$	112,790		0
Michael J. Kelleher		0		0		33,724			$	53,399
Clement E. Nadeau		0		0		29,508			$	46,723

(a)	Calculated based on the closing price on March 31, 2006 of National Grid plc ordinary shares traded on the London Stock Exchange (£5.725).
(b)	A conversion rate of $1.74/£1.00 was used to translate the option value, which is the exchange rate for the National Grid companies’ balance sheet at March 31, 2006.
(c)	The performance condition associated with grants of stock options made on June 18, 2001 to Messrs. Cochrane and Jesanis was tested in March 2006 and was not met. As a result, these options have lapsed and are no longer exercisable.

The following table sets forth, for the Named Executive Officers, exercises of SARs in fiscal year 2006, the realized value or spread (the difference between the exercise price and market value on the date of exercise) and the number and unrealized spread of the unexercised options and SARs held by each at fiscal year-end.

					Number of Securities
					Underlying Unexercised
	SARs		Value		SARs At Fiscal				Value of Unexercised SARs
	Exercised		Realized		Year-End (#)				At Fiscal Year-End ($)(a)
Name	(#)		($)		Exercisable		Unexercisable		Exercisable		Unexercisable
William F. Edwards		0		0		0		0		0		0
John G. Cochrane		0		0		0		0		0		0
Michael Jesanis		0		0		0		0		0		0
Michael J. Kelleher		0		0		0		0		0		0
Clement E. Nadeau		12,312	$	308,703		0		0		0		0

(a) SAR grants were made under Niagara Mohawk’s Long Term Incentive Plan which was terminated when its parent, Niagara Mohawk Holdings, Inc. merged with a subsidiary of National Grid USA. At that time, outstanding grants of SARs were converted to SARs over National Grid Group American Depositary Shares using a specified exchange ratio.

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Pension Plans

Executive Supplement Retirement Benefit Table

Five-Year
Average	Annual Annuity Value Based On Years of Service
Compensation	15 Years		20 Years		25 Years		30 Years		35 Years		40 Years
$150,000	$	42,874	$	56,166	$	69,082	$	81,999	$	90,040	$	94,540
$200,000	$	58,874	$	77,166	$	94,957	$	112,749	$	124,040	$	130,040
$250,000	$	74,874	$	98,166	$	120,832	$	143,499	$	158,040	$	165,540
$300,000	$	90,874	$	119,166	$	146,707	$	174,249	$	192,040	$	201,040
$350,000	$	106,874	$	140,166	$	172,582	$	204,999	$	226,040	$	236,540
$400,000	$	122,874	$	161,166	$	198,457	$	235,749	$	260,040	$	272,040
$450,000	$	138,874	$	182,166	$	224,332	$	266,499	$	294,040	$	307,540
$500,000	$	154,874	$	203,166	$	250,207	$	297,249	$	328,040	$	343,040
$550,000	$	160,124	$	210,166	$	258,957	$	307,749	$	340,290	$	355,290
$600,000	$	165,374	$	217,166	$	267,707	$	318,249	$	352,540	$	367,540
$650,000	$	170,624	$	224,166	$	276,457	$	328,749	$	364,790	$	379,790
$700,000	$	175,874	$	231,166	$	285,207	$	339,249	$	377,040	$	392,040
$750,000	$	181,124	$	238,166	$	293,957	$	349,749	$	389,290	$	404,290
$800,000	$	186,374	$	245,166	$	302,707	$	360,249	$	401,540	$	401,541
$850,000	$	191,624	$	252,166	$	311,457	$	370,749	$	413,790	$	428,790
$900,000	$	196,874	$	259,166	$	320,207	$	381,249	$	426,040	$	441,040
$1,000,000	$	207,374	$	273,166	$	337,707	$	402,249	$	450,540	$	465,540
$1,100,000	$	217,874	$	287,166	$	355,207	$	423,249	$	475,040	$	490,040
$1,200,000	$	228,374	$	301,166	$	372,707	$	444,249	$	499,540	$	514,540
$1,300,000	$	238,874	$	315,166	$	390,207	$	465,249	$	524,040	$	539,040
$1,400,000	$	249,374	$	329,166	$	407,707	$	486,249	$	548,540	$	563,540
$1,500,000	$	259,874	$	343,166	$	425,207	$	507,249	$	573,040	$	588,040
$1,600,000	$	270,374	$	357,166	$	442,707	$	528,249	$	597,540	$	612,540

The table above shows the maximum retirement benefit an executive officer can earn in aggregate under the applicable tax-qualified plan (described below) together with the ESRP. In developing the ESRP benefit, final compensation includes both base salary and annual incentive pay. The benefit calculations are made as of March 31, 2006 and assume the officer has selected a straight life annuity commencing at age 65. Annual compensation limits of $210,000 under a tax-qualified plan will reduce the portion payable under the qualified pension plan for some highly compensated officers. The benefits listed are shown without any joint and survivor benefits. If a participant elected a 100 percent joint and survivor benefit at age 65, with a spouse of the same age, the benefit shown in the table would be reduced by approximately 16 percent.

For purposes of the pension program, the Named Executive Officers had approximately the following credited years of benefit service at March 31, 2006: William F. Edwards, 27 years; John G.Cochrane, 25 years; Michael E. Jesanis, 22 years; Michael J. Kelleher, 17 years; and Clement E. Nadeau, 33 years.

Tax-Qualified Pension Plans: National Grid USA Companies Final Average Pay Pension Plan and Niagara Mohawk Pension Plan.

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Depending on their company origin prior to the merger of Niagara Mohawk Holdings with a subsidiary of National Grid USA, the Named Executive Officers participate in one of two qualified pension plans: the National Grid USA Companies Final Average Pay Pension Plan (FAPP) or the Niagara Mohawk Pension Plan (Nimo Plan). Both FAPP and the Nimo Plan are noncontributory, tax-qualified defined benefit plans which between them provide a retirement benefit to substantially all employees of the National Grid USA companies. Pension benefits are related to compensation, subject to the maximum annual limits noted in the table above.

Under FAPP, a participant’s retirement benefit is computed using formulas based on percentages of highest average compensation computed over five consecutive years. The compensation covered by FAPP includes salary, bonus and incentive share awards.

Under the Nimo Plan, a participant’s retirement benefit is based on one of two formulas depending on age and years of service on July 1, 1998: the cash balance formula, or the highest five-year average compensation. Under the cash balance formula a participant’s retirement benefit grows monthly, according to pay credits (from 4 percent to 8 percent times base salary) plus interest credits. Messrs. Edwards, Kelleher and Nadeau will receive the retirement benefit resulting from the higher of the two formulas.

Nonqualified Pension Plan: Executive Supplemental Retirement Plan

The Executive Supplemental Retirement Plan (ESRP) is a noncontributory, nonqualified defined benefit plan that provides additional retirement benefits to each of the Named Executive Officers and other members of management who are eligible to receive either a FAPP or Nimo Plan benefit and whose compensation exceeds legal limits under the applicable plan, whose deferred compensation is not eligible for inclusion under the FAPP or NiMo Plan, or who are otherwise selected for participation. Depending on the participant, the ESRP may provide for unreduced benefits payable as early as age 55, enhance the qualified plan formula, give credit for more years of service, take into account certain deferred compensation, and/or award benefits not otherwise payable due to limits on benefits that can be provided under the qualified plan. Mr. Nadeau and other ESRP participants who formerly participated in the Niagara Mohawk Supplemental Executive Retirement Plan (Niagara Mohawk SERP) are entitled to the pension benefit paid under the NiMo Plan, plus the higher of the pension benefit paid under the ESRP or that paid under the Niagara Mohawk SERP. The SERP benefit paid under the Niagara Mohawk was frozen at the time of the merger of Niagara Mohawk Holdings with a subsidiary of National Grid USA. For Mr. Nadeau, that amount is frozen as an annual annuity of $45,770. Mr. Edwards and Mr. Kelleher received the Niagara Mohawk SERP benefit at the merger and are eligible to receive a pension benefit under the ESRP, to be offset by the SERP benefit already received.

Employment Contracts, Termination of Employment and Change-in-Control Arrangements

Employment contracts. Of the Named Executive Officers, only Mr. Jesanis has an employment contract. His agreement sets forth his salary and certain benefits, and provides for 12 months’ written notice for termination other than for cause or disability. There are no termination or change-in-control arrangements particular to Mr. Jesanis.

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Termination without cause. For termination without cause, each of the Named Executive Officers except for Mr. Jesanis is entitled to a lump sum equal to two times his annualized base pay and bonus under the National Grid USA Companies’ Executive Severance Plan. The plan also provides for a lump sum payment to cover the employer’s contribution toward health insurance premiums for 18 months, a pro-rated bonus if the executive worked at least six months that year and outplacement counseling for 18 months.

Change in control. Under the National Grid USA Companies’ Incentive Compensation Plan, in the event of a change in control, each Named Executive Officer would receive a cash payment in an amount equal to the average annual bonus percentage for the incentive compensation plan level for the three prior years multiplied by that officer’s annualized base compensation. These payments would be made in lieu of the bonuses under these plans for the year in which the change in control occurs.

Messrs. Edwards and Cochrane each have a change of control agreement with National Grid USA providing for severance payments and benefits in the event that employment is terminated without cause or the executive terminates with good reason within 36 months after a change in control or other qualifying transaction. In addition to any other compensation and benefits payable under executive plans, but subject to certain limits tied to applicable tax law, the executive will be entitled to a lump sum cash payment equal to three times the sum of his annual base salary plus bonus; a lump sum cash payment for the amount he would have accrued under each pension plan had he remained employed for an additional 36 months; and reimbursement of legal fees and expenses, if any, that he incurs in disputing in good faith any issue relating to the agreement.

Post-employment health and life insurance. At retirement, the Named Executive Officers may become eligible for post-retirement health and life insurance benefits determined based on their age and years of service. The executive may be required to contribute to the cost of benefits. Under a retiree health care plan applicable to Messrs. Cochrane and Jesanis, post-employment health care benefits are protected for three years following a change in control. Messrs. Cochrane, Edwards and Jesanis have agreements that provide for three times base pay life insurance coverage for life. Mr. Edwards has an agreement providing for health care benefits for him and his dependents for their lifetimes.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table indicates the number of ordinary shares of National Grid plc beneficially owned as of June 1, 2006 by: (a) each of the Named Executive Officers; (b) each director of the Company; and (c) all directors and executive officers of the Company as a group. Except as indicated, each such person has sole investment and voting power with respect to the shares shown as being beneficially owned by such person, based on information provided to the Company. Each person listed in this table owns less than one percent of the outstanding equity securities of National Grid. Niagara Mohawk Holdings, Inc. owns all of the common stock of the Company.

67

	Number of Shares
Name	Beneficially Owned*
William F. Edwards		98,921
John G. Cochrane		95,775
Michael E. Jesanis		147,240
Michael J. Kelleher		33,724
Clement E. Nadeau		45,753
Barbara A. Hassan		48,513
Cheryl A. LaFleur		76,664
Anthony C. Pini		76,007
All directors and executive officers as a group (13 persons) (a) (b)		889,317

*	This number is expressed in terms of ordinary shares. It includes American Depositary Shares listed on the New York Stock Exchange, each of which represents five ordinary shares.
(a)	The Company’s directors and executive officers are listed in Item 10.
(b)	Includes shares held by Mr. Reilly’s spouse.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

PricewaterhouseCoopers LLP served as an independent registered public accounting firm of the Company for the fiscal year ended March 31, 2006.

Audit Fees

The aggregate fees billed by PricewaterhouseCoopers LLP for the audit of the Company’s financial statements and regulatory filings for the fiscal year ended March 31, 2006, and the reviews of quarterly reports on Form 10-Q filed during the fiscal year ended March 31, 2006 were $815,360. Fees billed by PricewaterhouseCoopers LLP for the audit of the Company’s financial statements and regulatory filings for the fiscal year ended March 31, 2005, and the reviews of quarterly reports on Form 10-Q filed during the fiscal year ended March 31, 2005 were $749,900.

Audit-related fees

There were no fees billed by PricewaterhouseCoopers LLP for assurance and related services that were reasonably related to the performance of the audit or review of the Company’s financial statements and are not disclosed under “Audit Fees” above in fiscal 2006.

Tax Fees

Fees billed by PricewaterhouseCoopers LLP to the Company for tax compliance, tax advice and tax planning were $42,489 in fiscal year 2006. Aggregate fees billed by PricewaterhouseCoopers LLP for these fees were $1,600 in fiscal year 2005.

68

All Other Fees

During the fiscal year ended March 31, 2006, the Company was billed fees by PricewaterhouseCoopers LLP totaling $95,700 for Sarbanes-Oxley Section 404 related services.

The Company did not pay any other type of fee for any other services from PricewaterhouseCoopers LLP during the fiscal year ended March 31, 2006.

The Company’s stockholders appoint the Company’s independent registered public accounting firm, with the approval of the Audit Committee of the Company’s indirect parent company, National Grid plc. Subject to any relevant legal requirements and National Grid plc’s Articles of Association, the Audit Committee is solely and directly responsible for the approval of the appointment, re-appointment, compensation and oversight of the Company’s independent registered public accounting firm. The Audit Committee must approve in advance all non-audit work to be performed by the independent registered public accounting firm.

During the fiscal year ended March 31, 2006, all of the above-described services provided by PricewaterhouseCoopers LLP were pre-approved by the Audit Committee.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Financial Statements

• Report of Independent Registered Public Accounting Firm

• Consolidated Statements of Operations, Consolidated Statements of Comprehensive Income, and Consolidated Statements of Retained Earnings for each of the three years in the period ended March 31, 2006.

• Consolidated Balance Sheets at March 31, 2006 and 2005.

• Consolidated Statements of Cash Flows for each of the three years in the period ended March 31, 2006.

• Notes to the Consolidated Financial Statements.

Exhibits

The exhibit index is incorporated herein by reference.

Financial Statement Schedule

Schedule II – Valuation and Qualifying Accounts and Reserves

69

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

(In thousands of dollars)
Column A	Column B		Column C		Column D		Column E
			Additions
	Balance at		Charged to				Balance
	Beginning		Costs and		Deductions		at End
Description	of Period		Expenses		(a)		of Period
Allowance for Doubtful Accounts - Deducted from Accounts Receivable in the Consolidated Balance Sheets
Year ended March 31, 2006	$	126,084	$	41,308	$	44,082	$	123,310
Year ended March 31, 2005		124,231		44,779		42,926		126,084
Year ended March 31, 2004		100,223		64,102		40,094		124,231

(a) Uncollectible accounts written off net of recoveries.

70

SIGNATURES

Pursuant to the Requirements of Section 13 or 15(d) 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 authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company.

		NIAGARA MOHAWK POWER CORPORATION
Date: June 29, 2006	By:	/s/ William F. Edwards
		William F. Edwards
		President

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, this report has been signed below on June 29, 2006 by the following persons on behalf of the registrant and in the capacities indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company.

Signature	Title
/s/ William F. Edwards	President and Director (Principal Executive Officer)
William F. Edwards
/s/ John G. Cochrane John G. Cochrane	Chief Financial Officer (Principal Financial Officer)
/s/ Paul J. Bailey Paul J. Bailey	Controller (Principal Accounting Officer)
/s/ Michael E. Jesanis Michael E. Jesanis	Director
/s/ Clement E. Nadeau Clement E. Nadeau	Director
/s/ Barbara A. Hassan Barbara A. Hassan	Director
/s/ Michael J. Kelleher Michael J. Kelleher	Director

71

Signature	Title
/s/ Cheryl A. LaFleur Cheryl A. LaFleur	Director
/s/ Anthony C. Pini Anthony C. Pini	Director

72

NIAGARA MOHAWK POWER CORPORATION

EXHIBIT INDEX

Each document referred to in this Exhibit Index is incorporated by reference to the files of the Securities and Exchange Commission, unless designated with an asterisk. The cross-reference table below sets forth the registration statements and reports from which the exhibits are incorporated by reference.

Reference	Name
A	Niagara Mohawk Registration Statement No. 2-8214
B	Niagara Mohawk Registration Statement No. 2-8634
C	Central New York Power and Light Corporation Registration Statement No. 2-3414
D	Central New York Power and Light Corporation Registration Statement No. 2-5490
E	Niagara Mohawk Registration Statement No. 2-10501
F	Niagara Mohawk Registration Statement No. 2-12443
G	Niagara Mohawk Registration Statement No. 2-16193
H	Niagara Mohawk Registration Statement No. 2-26918
I	Niagara Mohawk Registration Statement No. 2-59500
J	Niagara Mohawk Registration Statement No. 2-70860
K	Niagara Mohawk Registration Statement No. 33-38093
L	Niagara Mohawk Registration Statement No. 33-47241
M	Niagara Mohawk Registration Statement No. 33-59594
N	Niagara Mohawk Registration Statement No. 33-49541
O	Niagara Mohawk Annual Report on Form 10-K for year ended December 31, 1994
P	Niagara Mohawk Annual Report on Form 10-K for year ended December 31, 1997
Q	Niagara Mohawk Annual Report on Form 10-K for year ended December 31, 1999

73

Reference	Name
R	Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended March 31, 1993
S	Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended September 30, 1993
T	Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended June 30, 1995
U	Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended March 31, 1998
V	Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended June 30, 1998
W	Niagara Mohawk Quarterly Report of Form 10-Q for quarter ended March 31, 1999
X	Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended September 30, 2001
Y	Niagara Mohawk Current Report on Form 8-K dated July 9, 1997
Z	Niagara Mohawk Current Report on Form 8-K dated October 10, 1997
AA	Niagara Mohawk Current Report on Form 8-K dated November 30, 1999
BB	Niagara Mohawk Current Report on Form 8-K dated May 9, 2000
CC	Niagara Mohawk Current Report on Form 8-K dated September 25, 2001
DD	Niagara Mohawk Annual Report on Form 10-K for the fiscal year ended March 31, 2003
EE	Niagara Mohawk Annual Report on Form 10-K for the fiscal year ended March 31, 2004
FF	New England Electric System Annual Report on Form 10-K for the fiscal year ended December 31, 1997
GG	New England Electric System Annual Report on Form 10-K for the fiscal year ended December 31, 1998

74

Reference	Name
HH	New England Power Company Annual Report on Form 10-K for the fiscal year ended March 31, 2002
II	National Grid Group Registration Statement on Form S-8 filed July 26, 2001
JJ	National Grid Group Annual Report on Form 20-F for the fiscal year ended March 31, 2002
KK	National Grid Transco Annual Report on Form 20-F for the fiscal year ended March 31, 2004
LL	National Grid Transco Annual Report on Form 20-F for the fiscal year ended March 31, 2005
MM	Niagara Mohawk Annual Report on Form 10-K for the fiscal year ended March 31, 2005
NN	National Grid plc Annual Report on Form 20-F for the fiscal year ended March 31, 2006

In accordance with Paragraph 4(iii) of Item 601 (b) of Regulation S-K, the Company agrees to furnish to the Securities and Exchange Commission, upon request, a copy of the agreements comprising the $804 million senior bank financing that the Company completed with a bank group on June 1, 2000, and subsequently amended. The total amount of long-term debt authorized under such agreement does not exceed ten % of the total consolidated assets of the Company and its subsidiaries.

75

	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
3(a)(1)	O	3(a)(1)	Certificate of Consolidation of New York Power and Light Corporation, Buffalo Niagara Electric Corporation and Central New York Power Corporation, filed in the office of the New York Secretary of State, January 5, 1950
3(a)(2)	O	3(a)(2)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk, filed in the office of the New York Secretary of State, January 5, 1950
3(a)(3)	O	3(a)(3)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk pursuant to Section 36 of the Stock Corporation Law of New York, filed August 22, 1952, in the office of the New York Secretary of State
3(a)(4)	O	3(a)(4)	Certificate of Niagara Mohawk pursuant to Section 11 of the Stock Corporation Law of New York filed May 5, 1954 in the office of the New York Secretary of State
3(a)(5)	O	3(a)(5)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk pursuant to Section 36 of the Stock Corporation Law of New York, filed January 9, 1957 in the office of the New York Secretary of State
3(a)(6)	O	3(a)(6)	Certificate of Niagara Mohawk pursuant to Section 11 of the Stock Corporation Law of New York, filed May 22, 1957 in the office of the New York Secretary of State
3(a)(7)	O	3(a)(7)	Certificate of Niagara Mohawk pursuant to Section 11 of the Stock Corporation Law of New York, filed February 18, 1958 in the office of the New York Secretary of State
3(a)(8)	O	3(a)(8)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 5, 1965 in the office of the New York Secretary of State
3(a)(9)	O	3(a)(9)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 24, 1967 in the office of the New York Secretary of State

76

	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
3(a)(10)	O	3(a)(10)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 19, 1968 in the office of the New York Secretary of State
3(a)(11)	O	3(a)(11)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed September 22, 1969 in the office of the New York Secretary of State
3(a)(12)	O	3(a)(12)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 12, 1971 in the office of the New York Secretary of State
3(a)(13)	O	3(a)(13)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 18, 1972 in the office of the New York Secretary of State
3(a)(14)	O	3(a)(14)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed June 26, 1973 in the office of the New York Secretary of State
3(a)(15)	O	3(a)(15)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 9, 1974 in the office of the New York Secretary of State
3(a)(16)	O	3(a)(16)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed March 12, 1975 in the office of the New York Secretary of State
3(a)(17)	O	3(a)(17)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 7, 1975 in the office of the New York Secretary of State

77

	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
3(a)(18)	O	3(a)(18)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 27, 1975 in the office of the New York Secretary of State
3(a)(19)	O	3(a)(19)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 7, 1976 in the office of the New York Secretary of State
3(a)(20)	O	3(a)(20)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed September 28, 1976 in the office of the New York Secretary of State
3(a)(21)	O	3(a)(21)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed January 27, 1978 in the office of the New York Secretary of State
3(a)(22)	O	3(a)(22)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 8, 1978 in the office of the New York Secretary of State
3(a)(23)	O	3(a)(23)	Certificate of Correction of the Certificate of Amendment filed May 7, 1976 of the Certificate of Incorporation under Section 105 of the Business Corporation Law of New York, filed July 13, 1978 in the office of the New York Secretary of State
3(a)(24)	O	3(a)(24)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed July 17, 1978 in the office of the New York Secretary of State
3(a)(25)	O	3(a)(25)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed March 3, 1980 in the office of the New York Secretary of State

78

	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
3(a)(26)	O	3(a)(26)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed March 31, 1981 in the office of the New York Secretary of State
3(a)(27)	O	3(a)(27)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed March 31, 1981 in the office of the New York Secretary of State
3(a)(28)	O	3(a)(28)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed April 22, 1981 in the office of the New York Secretary of State
3(a)(29)	O	3(a)(29)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 8, 1981 in the office of the New York Secretary of State
3(a)(30)	O	3(a)(30)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed April 26, 1982 in the office of the New York Secretary of State
3(a)(31)	O	3(a)(31)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed January 24, 1983 in the office of the New York Secretary of State
3(a)(32)	O	3(a)(32)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 3, 1983 in the office of the New York Secretary of State
3(a)(33)	O	3(a)(33)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed December 27, 1983 in the office of the New York Secretary of State

79

	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
3(a)(34)	O	3(a)(34)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed December 27, 1983 in the office of the New York Secretary of State
3(a)(35)	O	3(a)(35)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed June 4, 1984 in the office of the New York Secretary of State
3(a)(36)	O	3(a)(36)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 29, 1984 in the office of the New York Secretary of State
3(a)(37)	O	3(a)(37)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed April 17, 1985 in the office of the New York Secretary of State
3(a)(38)	O	3(a)(38)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 3, 1985 in the office of the New York Secretary of State
3(a)(39)	O	3(a)(39)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed December 24, 1986 in the office of the New York Secretary of State
3(a)(40)	O	3(a)(40)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed June 1, 1987 in the office of the New York Secretary of State
3(a)(41)	O	3(a)(41)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed July 20, 1987 in the office of the New York Secretary of State

80

	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
3(a)(42)	O	3(a)(42)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 27, 1988 in the office of the New York Secretary of State
3(a)(43)	O	3(a)(43)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed September 27, 1990 in the office of the New York Secretary of State
3(a)(44)	O	3(a)(44)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed October 18, 1991 in the office of the New York Secretary of State
3(a)(45)	O	3(a)(45)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 5, 1994 in the office of the New York Secretary of State
3(a)(46)	O	3(a)(46)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 5, 1994 in the office of the New York Secretary of State
3(a)(47)	V	3	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed June 29, 1998 in the office of the New York Secretary of State
3(a)(48)	W	3	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed March 19, 1999 in the office of the New York Secretary of State
3(a)(49)	AA	3.1	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed November 29, 1999 in the office of the New York Secretary of State

81

	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
3(b)	U	3(i)	By-Laws of Niagara Mohawk, as amended March 17, 1999
4(a)	O	4(b)	Agreement to furnish certain debt instruments
4(b)(1)	C	**	Mortgage Trust Indenture dated as of October 1, 1937 between Niagara Mohawk (formerly CNYP) and Marine Midland Bank, N.A. (formerly named The Marine Midland Trust Company of New York), as Trustee
4(b)(2)	I	2-3	Supplemental Indenture dated as of December 1, 1938, supplemental to Exhibit 4(1)
4(b)(3)	I	2-4	Supplemental Indenture dated as of April 15, 1939, supplemental to Exhibit 4(1)
4(b)(4)	I	2-5	Supplemental Indenture dated as of July 1, 1940, supplemental to Exhibit 4(1)
4(b)(5)	D	7-6	Supplemental Indenture dated as of October 1, 1944, supplemental to Exhibit 4(1)
4(b)(6)	I	2-8	Supplemental Indenture dated as of June 1, 1945, supplemental to Exhibit 4(1)
4(b)(7)	I	2-9	Supplemental Indenture dated as of August 17, 1948, supplemental to Exhibit 4(1)
4(b)(8)	A	7-9	Supplemental Indenture dated as of December 31, 1949, supplemental to Exhibit 4(1)
4(b)(9)	A	7-10	Supplemental Indenture dated as of January 1, 1950, supplemental to Exhibit 4(1)
4(b)(10)	B	7-11	Supplemental Indenture dated as of October 1, 1950, supplemental to Exhibit 4(1)

** Filed October 15, 1937 after effective date of Registration Statement No. 2-3414.

82

	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
4(b)(11)	B	7-12	Supplemental Indenture dated as of October 19, 1950, supplemental to Exhibit 4(1)
4(b)(12)	E	4-16	Supplemental Indenture dated as of February 20, 1953, supplemental to Exhibit 4(1)
4(b)(13)	F	4-19	Supplemental Indenture dated as of April 25, 1956, supplemental to Exhibit 4(1)
4(b)(14)	G	2-23	Supplemental Indenture dated as of March 15, 1960, supplemental to Exhibit 4(1)
4(b)(15)	H	4-29	Supplemental Indenture dated as of July 15, 1967, supplemental to Exhibit 4(1)
4(b)(16)	J	4(b)(42)	Supplemental Indenture dated as of March 1, 1978, supplemental to Exhibit 4(1)
4(b)(17)	J	4(b)(46)	Supplemental Indenture dated as of June 15, 1980, supplemental to Exhibit 4(1)
4(b)(18)	K	4(b)(75)	Supplemental Indenture dated as of November 1, 1990, supplemental to Exhibit 4(1)
4(b)(19)	L	4(b)(77)	Supplemental Indenture dated as of October 1, 1991, supplemental to Exhibit 4(1)
4(b)(20)	M	4(b)(79)	Supplemental Indenture dated as of June 1, 1992, supplemental to Exhibit 4(1)
4(b)(21)	M	4(b)(81)	Supplemental Indenture dated as of August 1, 1992, supplemental to Exhibit 4(1)
4(b)(22)	R	4(b)(82)	Supplemental Indenture dated as of April 1, 1993, supplemental to Exhibit 4(1)
4(b)(23)	S	4(b)(83)	Supplemental Indenture dated as of July 1, 1993, supplemental to Exhibit 4(1)

83

	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
4(b)(24)	O	4(86)	Supplemental Indenture dated as of July 1, 1994, supplemental to Exhibit 4(1)
4(b)(25)	T	4(87)	Supplemental Indenture dated as of May 1, 1995, supplemental to Exhibit 4(1)
4(b)(26)	N	4(a)(39)	Supplemental Indenture dated as of March 20, 1996, supplemental to Exhibit 4(1)
4(b)(27)	Q	4(b)40	Supplemental Indenture dated as of November 1, 1998, supplemental to Exhibit 4(1)
4(c)	N	4(a)(41)	Form of Indenture relating to the Senior Notes dated June 30, 1998
4(d)(1)	BB	1.2	Indenture, dated as of May 12, 2000, between Niagara Mohawk Power Corporation, a New York Corporation, and The Bank of New York, a New York banking corporation, as Trustee
4(d)(2)	BB	1.3	First Supplemental Indenture, dated as of May 12, 2000, between Niagara Mohawk Power Corporation, a New York corporation, and The Bank of New York, a New York banking corporation, as Trustee
4(d)(3)	CC	1.2	Form of Second Supplemental Indenture, between Niagara Mohawk Power Corporation and The Bank of New York, as Trustee
4(e)(1)	DD	4(e)(1)	Supplemental Indenture, dated as of May 1, 2003, between Niagara Mohawk Power Corporation and HSBC Bank USA, as Trustee
4(e)(2)	DD	4(e)(2)	First Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $100,000,000 Pollution Control Revenue Bonds, 1985 Series A

84

	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
4(e)(3)	DD	4(e)(3)	First Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $37,500,000 Pollution Control Revenue Bonds, 1985 Series B
4(e)(4)	DD	4(e)(4)	First Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $37,500,000 Pollution Control Revenue Bonds, 1985 Series C
4(e)(5)	DD	4(e)(5)	First Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $50,000,000 Pollution Control Revenue Bonds, 1986 Series A
4(e)(6)	DD	4(e)(6)	Second Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $25,760,000 Pollution Control Revenue Bonds, 1987 Series A
4(e)(7)	DD	4(e)(7)	Second Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $93,200,000 Pollution Control Revenue Bonds, 1987 Series B
4(e)(8)	DD	4(e)(8)	Second Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $69,800,000 Pollution Control Revenue Bonds, 1988 Series A
4(e)(9)	EE	4(e)(9)	Supplemental Indenture , dated as of December 1, 2003, between Niagara Mohawk Power Corporation and HSBC Bank USA, as Trustee

85

	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
4(e)(10)	EE	4(e)(10)	First Supplemental Participation Agreement, dated as of December 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $45,600,000 Pollution Control Refunding Revenue Bonds, 1991 Series A
4(e)(11)	EE	4(e)(11)	Supplemental Indenture, dated as of May 1, 2004, between Niagara Mohawk Corporation and HSBC Bank USA, as Trustee
4(e)(12)	EE	4(e)(12)	Participation Agreement, dated as of May 1, 2004, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to Pollution Control Revenue Bonds, 2004 Series A
10(a)	Y	10.28	Master Restructuring Agreement dated July 9, 1997 among Niagara Mohawk and the 16 independent power producers signatory thereto
10(b)	Z	99-9	Power Choice settlement filed with the PSC on October 10, 1997
10(c)	P	10-13	PSC Opinion and Order regarding approval of the Power Choice settlement agreement with PSC, issued and effective March 20, 1998
10(d)	U	10(c)	Amendments to the Master Restructuring Agreement
10(e)	Q	10-14	Independent System Operator Agreement dated December 2, 1999
10(f)	Q	10-15	Agreement between New York Independent System Operator and Transmission Owners dated December 2, 1999
10(g)	X	10-9	PSC Opinion and Order regarding approval of the sale of Nine Mile Point Nuclear Station Units No. 1 and No. 2
10(h)	X	10-10	Merger Rate Agreement reached among Niagara Mohawk, the PSC staff and other parties, filed with the PSC on October 11, 2001

86

	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
10(i)	GG	10(y)	Severance Protection Agreement between New England Electric System and John G. Cochrane dated March 1, 1998
	MM	10(i)	Amendment to Severance Protection Agreement dated December 9, 1998
			Amendment to Severance Protection Agreement dated March 15, 2003
			Amendment to Severance Protection Agreement dated September 1, 2003
10(j)	MM	10(j)	Letter Agreement between National Grid USA and William F. Edwards dated January 16, 2002
			Agreement between National Grid USA and William F. Edwards effective March 15, 2005
10(k)	LL	4.5	Service Agreement among National Grid Transco plc, National Grid USA and Michael E. Jesanis dated July 8, 2004
10(l)	GG	10(y)	Severance Protection Agreement between New England Electric System and Lawrence J. Reilly dated February 25, 1997
	MM	10(l)	Amendment to Severance Protection Agreement dated December 9, 1998
			Amendment to Severance Protection Agreement dated March 15, 2003
10(m)	HH	10(l)	National Grid USA Companies’ Deferred Compensation Plan Amended and Restated December 6, 2001
	MM	10(n)	Amendment to National Grid USA Companies’ Deferred Compensation Plan dated April 1, 2002
	MM	10(n)	Amendment to National Grid USA Companies’ Deferred Compensation Plan dated September 1, 2003
	*		Amendment to National Grid USA Companies’ Deferred Compensation Plan dated December 22, 2005

87

	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
10(n)	MM	10(o)	National Grid USA Companies’ Executive Severance Plan Amended and Restated March 1, 2003
			Amendment to National Grid USA Companies’ Executive Severance Plan dated September 1, 2003
10(o)	HH	10(n)	National Grid USA Companies’ Executive Supplemental Retirement Plan Revised and Restated December 21, 2001
	MM	10(p)	Amendment to National Grid USA Companies’ Executive Supplemental Retirement Plan dated February 1, 2002
			Amendment to National Grid USA Companies’ Executive Supplemental Retirement Plan dated August 1, 2003
			Amendment to National Grid USA Companies’ Executive Supplemental Retirement Plan dated September 1, 2003
10(p)	FF	10(o)	New England Electric Companies’ Executive Retirees Health and Life Insurance Plan as Amended and Restated January 1, 1996
10(q)	MM	10(r)	National Grid USA Companies’ Incentive Compensation Plan as Amended and Restated March 1, 2003
			Amendment to National Grid USA Companies’ Incentive Compensation Plan dated September 1, 2003
10(r)	KK	4.19	National Grid Transco Performance Share Plan 2002 (as approved July 23, 2002 by a resolution of the shareholders of National Grid Group plc, adopted October 17, 2002 by a resolution of the Board of National Grid Group plc, amended June 26, 2003 by the Share Schemes Sub-Committee of National Grid Transco plc, and amended May 5, 2004 by the Share Schemes Sub-Committee of National Grid Transco plc)
	JJ	4(c)	National Grid Executive Share Option Plan 2002
	JJ	4(c)	National Grid Group Share Matching Plan 2002
	II	4C	National Grid Executive Share Option Plan 2000
	II	4D	National Grid Executive Share Option Scheme
10(s)	MM	10(u)	Niagara Mohawk Long Term Incentive Plan as amended through September 28, 2000

88

	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
10(t)	Q	10-24	Niagara Mohawk Supplemental Executive Retirement Plan Amended and Restated as of January 1, 1999
	MM	10(v)	Amendment 1 to the Niagara Mohawk Supplemental Executive Retirement Plan dated December 17, 1999
			Amendment to Niagara Mohawk Supplemental Executive Retirement Plan dated August 17, 2001
10(u)	NN	4(c).16	National Grid plc Deferred Share Plan
10(v)	*		National Grid USA Companies’ Executive Life Insurance Plan
10(w)	*		Collateral Assignment Agreement between New England Power Service Company and John Cochrane
10(x)	*		Collateral Assignment Agreement between New England Power Service Company and Michael E. Jesanis dated March 23, 1993
10(y)	*		Collateral Assignment Agreement between National Grid USA Service Company, Inc. and Barbara A. Hassan dated July 1, 2000
10(z)	*		Collateral Assignment Agreement between New England Power Service Company and Cheryl A. LaFleur dated January 1, 1996
10(aa)	*		Collateral Assignment Agreement between Massachusetts Electric Company and Anthony C. Pini
10(bb)	*		Key Executive Plan of Eastern Utilities Associates, and First Amendment to the Eastern Utilities Associates Key Executive Plan
10(cc)	*		Split Dollar Assignment Insurance Agreement between EUA Service Corporation and Barbara A. Hassan effective as of February 1, 1995
21	*		Subsidiaries of the Registrant
31.1	*		Certifications of Principal Executive Officer
31.2	*		Certifications of Principal Financial Officer
32	*		Certifications furnished pursuant to 18 U.S.C. 1350

* Filed herewith.

89