UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

For the fiscal year ended March 31, 2005

OR

For the transition period___________to______________

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

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 an accelerated filer (as defined in Exchange Act Rule 12b-2). 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.

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NIAGARA MOHAWK POWER CORPORATION

TABLE OF CONTENTS

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FORWARD-LOOKING INFORMATION

This report and other presentations made by Niagara Mohawk Power Corporation (the Company) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Throughout this report, forward looking statements can be identified by the words or phrases “will likely result”, “are expected to”, “will continue”, “is anticipated”, “estimated”, “projected”, “believe”, “hopes”, or similar expressions. Although the Company believes that, in making any such statements, its expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to:

(a)		the impact of further electric and gas industry restructuring;
(b)		the impact of general economic changes in New York;
(c)		federal and state regulatory developments and changes in law, including those governing municipalization and exit fees;
(d)		federal regulatory developments concerning regional transmission organizations;
(e)		changes in accounting rules and interpretations, which may have an adverse impact on the Company’s statements of financial position, reported earnings and cash flows;
(f)		timing and adequacy of rate relief;
(g)		adverse changes in electric load;
(h)		acts of terrorism;
(i)		climatic changes or unexpected changes in weather patterns; and
(j)		failure to recover costs currently deferred under the provisions of Statement of Financial Accounting Standards (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).

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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 565,000 gas customers in areas of central, northern and eastern New York.

On January 31, 2002, Niagara Mohawk Holdings, Inc. (Holdings), the parent company of Niagara Mohawk Power Corporation, became a wholly owned subsidiary of National Grid USA (National Grid). National Grid is a wholly owned subsidiary of National Grid Transco plc (NGT).

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 New York Public Service Commission (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. See Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Merger Rate Plan: The Company’s electricity delivery rates are governed by a 10-year rate plan that became effective on January 31, 2002, the closing of the merger. Under the plan, after reflecting its share of savings related to the acquisition, the Company may earn a threshold return on equity for its electricity distribution business of 10.6%, or 12.0% if certain customer education targets are met, and half of any earnings in excess of that amount. The return on equity is calculated cumulatively from inception to December 31, 2005 and on a two year rolling basis thereafter. 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. This exclusion effectively offers the Company the potential to achieve a return in excess of the regulatory allowed return of 10.6%.

Under the Merger Rate Plan, the Company resets its competitive transition charge (CTC) every two years. The CTC reset is intended to account for changes in the forecast of electricity and natural gas commodity prices, and the effects those changes have on the Company’s above market payments under legacy power contracts that would otherwise be stranded. The next CTC reset filing is scheduled for August 1, 2005 and as part of that filing, the Company is also authorized to recover amounts exceeding $100 million in the deferral accounts (projected through the end of the 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 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. The Company will include a proposal to recover the excess balance of the deferral accounts of $127 million and a projection through the end of the two year period in its August 1, 2005 filing. The Company’s deferral recovery is subject to regulatory review and approval of the PSC.

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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.

Under the plan, gas delivery rates were frozen until the end of the 2004 calendar year, and the Company now has the right to request an increase at any time, if needed. The Company may earn a threshold return on equity of up to 10% or 12% if certain customer migration and education goals are met, and is required to share earnings above this threshold with customers.

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, in that the Company will provide electricity to its customers who are unable or unwilling to obtain an alternative supplier (which accounts for approximately 93% of the Company’s customers and 64% 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, 2005, the Company had approximately 52,000 pole miles of transmission and distribution lines for electric 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. Presently there are 12 separate distribution zones connected to 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).

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

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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, 2005 numbered approximately 4,600, of whom approximately 83 percent were union members. The Company, however, also receives substantial support for its activities from employees of National Grid USA Service Company, Inc. (Service Company), an affiliated company that provides administrative services support to all National Grid USA companies. The Company reimburses Service Company for the costs associated with those services.

In October 2004, we entered into a new 42-month contract with our labor union. The new contract will allow us to increase productivity through more efficient working practices and to improve safety and services. We believe our 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 to the colder or warmer temperature in that 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 to the colder temperatures in that more gas is used for heating during those months.

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

ITEM 2. PROPERTIES

Electric Transmission and Distribution: As of March 31, 2005, the Company’s electric transmission and distribution systems were composed of:

	•		748 substations with a rated transformer capacity of approximately 22,800,000 kilo-volt-amperes
	•		approximately 9,400 pole miles of overhead and underground transmission lines

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	•		approximately 36,000 conductor primary structure miles of overhead distribution lines
	•		about 6,300 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, 2005, the Company’s natural gas delivery system was comprised of approximately 8,500 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 Cayuga, Oneida, Mohawk, Seneca and Onondaga Nations. A court has awarded damages to the Cayuga Nation that are payable by the State of New York. The land claim litigation has not been resolved, although the St. Regis Mohawk Tribe recently entered into a settlement with New York State that could lead to resolution of the Mohawk’s land claims against parties including the Company. The Company continues to monitor the land claim litigation and, where necessary, defends its interests.

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

ITEM 3. LEGAL PROCEEDINGS

During the last quarter of the fiscal year ended March 31, 2005, the Company settled New York State v. Niagara Mohawk Power Corp. et al. The New York State Attorney General had filed a civil action against the Company, NRG Energy, Inc. and certain of NRG’s affiliates in U.S. District Court for the Western District of New York for alleged violations of the Federal Clean Air Act, related state environmental statutes and the common law at the Huntley and Dunkirk power plants. In January 2005, the Company, the State and the NRG companies asked the Court to approve a settlement that would fully resolve all claims asserted in the litigation. An order was issued by the Court on June 3, 2005, approving the settlement and stating that a full decision will follow.

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, 2005. On May 5, 2005, by unanimous written consent of the sole common stockholder,

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	•		The following persons were elected as directors: William F. Edwards, Michael E. Jesanis, Clement E. Nadeau, Kwong O. Nuey, Jr. and Anthony C. Pini.
	•		The firm of PricewaterhouseCoopers LLP, an independent registered public accounting firm, was appointed the Company’s auditor for the fiscal year ending March 31, 2006.

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 Holdings, and therefore indirectly by National Grid and NGT. 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 2005. 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 new 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, 2005, 2004 and 2003, the sixty day period ended March 31, 2002, the thirty day period ended January 30, 2002, the three months ended March 31, 2001, the years ended December 31, 2001 and 2000. 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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ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Merger with National Grid: On January 31, 2002, the acquisition of Holdings by National Grid was completed for a value of approximately $3.0 billion in cash and American Depositary Shares. The acquisition 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. The purchase accounting method required the Company to revalue its assets and liabilities at their fair value. This revaluation resulted in an increase to the Company’s pension and postretirement benefit liability in the amount of approximately $440 million, with a corresponding offsetting increase to a regulatory asset account. See Item 8. Financial Statements and Supplementary Data, - Note H - Employee Benefits for a discussion of the Company’s pension and postretirement benefit plans.

VEROs: In fiscal 2004, National Grid made a voluntary early retirement offer (VERO) to eligible non-union employees in areas including transmission and corporate administrative functions such as finance, human resources, legal and information technology. A total of 53 employees of the Company accepted the VERO. The majority of them retired by November 1, 2004, with the remainder retiring by November 1, 2007. The Company expensed approximately $19 million of VERO costs in fiscal year 2004. This amount included approximately $9 million allocated to the Company from Service Company, an affiliate.

In January 2002, the Company made a VERO to 302 eligible non-union employees in targeted areas where significant workforce reductions were necessary in the combined organization, primarily corporate administrative functions such as finance, human resources, legal and information technology. The number of eligible employees that accepted the VERO was 267 and most retired by June 30, 2002, with the last employees retiring by March 31, 2004. Under the Merger Rate Plan, the Company is allowed to record a regulatory asset for separation and early retirement costs. The amortization of such regulatory asset is occurring over ten years, with approximately 69 percent of the amortization of the regulatory asset occurring within the first three years. On January 31, 2002, the Company recorded a regulatory asset of $53 million related to the VERO. This regulatory asset had a balance of approximately $16 million and $22 million at March 31, 2005 and 2004, respectively.

Retail Bypass: 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

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permitted to bypass its retail charges. The FERC has issued three orders that directly conflict with Niagara Mohawk’s state-approved tariffs and the orders of the PSC on station service rates. These orders, if upheld, will permit these generators to bypass Niagara Mohawk’s state-jurisdictional station service charges for electricity. To the extent that the Company experiences any lost revenue attributable to retail bypass, it is permitted to recover these lost revenues under its rate plans. For further details of these orders and the related proceedings, see Item 8. Financial Statements and Supplementary Date, Note D – Commitments and Contingencies, under the captions “Retail Bypass” and “Niagara Mohawk Power Corp. v. Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C.”

PSC Issues: 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 $21 million pension settlement loss incurred in fiscal year 2004. For further discussion of the settlement losses, see Item 8. Financial Statements and Supplementary Data — Note H — Employee Benefits.

As part of the Company’s ongoing reconciliation of commodity costs and revenues, the Company identified several adjustments for the period from October 1, 2001 through April 30, 2003, and included them in filings with the PSC. Specifically, the Company requested recovery of $36 million of commodity costs associated with the under-reconciliation of New York Power Authority (NYPA) hydropower revenues in its commodity adjustment clause, and proposed to refund $24 million associated with other revenues that were not included in the commodity adjustment reconciliation. Following the filing, the PSC Staff completed a comprehensive audit of the Company’s commodity costs and revenues from October 1, 2001 through December 31, 2003, and the Staff and the Company agreed that a refund of $2.8 million should be provided to customers through that period. The PSC approved the refund on December 20, 2004.

Elevated equipment voltage: The PSC issued an order on January 5, 2005, requiring all electric utilities in the state to test annually all of their publicly accessible transmission and distribution facilities for elevated equipment voltage and perform visual inspections of all facilities on a five year schedule. As anticipated in the July 2004 order proposing the guidelines, the order contains strict compliance requirements and potential financial penalties for failure to achieve testing and inspection targets. Failure to meet the annual target for performing tests will result in a 0.75% reduction in return on equity, as will failure to meet the annual target for inspections. The costs to comply with this order are expected to be significant. Under its existing rate plan, the Company is eligible to recover through rates that portion of its costs that the PSC considers incremental. The Company, together with other utilities, has filed for rehearing on certain aspects of this order, including a request for more time to test remote areas of the service territory, a challenge to the PSC authority to impose penalties for non-compliance, and clarification that the PSC did not intend to impose a different standard for cost recovery for these programs than is otherwise specified in the Company’s pre-existing rate plan, among other clarifications. In February the Company filed plans for testing and inspections as required by the PSC and a petition to request an extended schedule to complete testing.

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 results of operations and the reported amounts of assets and

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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 (being the FERC, PSC, or other regulatory body having jurisdiction) will allow future recovery of those costs through rates. The Company bases its assessment of recovery by either 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 whether the 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 assets and liabilities would be recognized as current-period revenue or expense.

Amortization of regulatory assets is provided over the recovery period as allowed in the related regulatory agreement. Amortization of the stranded cost regulatory asset is shown separately (as 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).

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.

In addition to the market returns, various other assumptions also affect the pension and other post-retirement benefit expense and measurement of their respective obligations. The more significant assumptions include the assumed return on assets, discount rate, and in the case of retiree healthcare benefits, medical trend assumptions. 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

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

	•		Assumed return on assets. 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 our 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 our target asset allocation, and the resulting long-term return on asset rate is then applied to the market-related value of assets. For fiscal 2005, the Company used an 8.50% assumed return on assets for its pension plan and an 8.26% assumed return on assets for its other post-retirement benefits plans, respectively.
	•		Discount rate. In determining the discount rate, the Company considers Moody’s Aa rates for corporate bonds and public utility bonds. In addition, the Company considers other measures of interest rates for high quality fixed income investments which match the duration of the liabilities. A rate is chosen within the range set by these measures.
	•		Medical trend assumptions. The health care cost trend rate is the assumed rate of increase in per-capita health care charges. For 2005, the health trend was set at 10% with the ultimate trend of 5% reached in 2009.

Goodwill: The company applies the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (FAS 142). In accordance with FAS 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.

Tax Provision: The Company’s 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 IRS approval.

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” (FAS 133), and SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” as amended. Under the provisions of FAS 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 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

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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 years ended March 31, 2005 and 2004.

EARNINGS

Net income for the year ended March 31, 2005 increased by approximately $124 million from the prior 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.

Net income for the year ended March 31, 2004 increased by approximately $14 million from the prior year. This increase is primarily due to the reduced interest costs from the redemption or refinancing of long-term debt using lower cost associated company debt or funds from the intercompany money pool. Partially offsetting these cost reductions were lower sales of both electricity and gas due to more normal weather conditions in the current year than in the prior year. See the following discussions of revenues and operating expenses for more detailed explanations.

REVENUES

Electric revenues decreased $167 million during the year ended March 31, 2005 from the prior year. Electric revenues decreased $27 million in the twelve months ended March 31, 2004 from the prior year. The table below details components of this fluctuation.

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. Since the start of electricity deregulation in the State of New York, retail electric customers have been migrating to competitive suppliers for their commodity requirements which is a contributing factor for the decrease in retail sales revenues in the years ended March 31, 2005 and 2004. These decreases were partially offset by increases in

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the price of electricity that was passed on to customers, and higher stranded cost revenues matching increased stranded cost amortization.

Sales for resale represent sales of electricity to the New York Independent System Operator (NYISO) at the market price of electricity. All electricity purchased under certain purchased power contracts is sold to the NYISO. The decrease in sales to the NYISO for the year ended March 31, 2005 was due to the expiration of some of these contracts. The increase in sales to the NYISO for the year ended March 31, 2004 was attributable to higher electricity prices as compared to the prior year.

Electric kilowatt-hour sales were approximately 36.6 billion and 38.5 billion for the year ended March 31, 2005 and 2004. The table below details components of this fluctuation.

Gas revenues increased $28 million in the fiscal year ended March 31, 2005 from the prior year. This increase is primarily a result of 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 prior year period ended March 31, 2004 and reversed in the year ended March 31, 2005.

Gas revenues increased $71 million for the fiscal year ended March 31, 2004 compared to the prior year ended March 31, 2003 primarily due to higher prices of gas purchases, which are being passed through to customers. This increase is partially offset by an adjustment related to state net income tax.

The table below details components of the gas revenue fluctuation:

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, 2005, excluding transportation of customer-owned gas, decreased approximately 3.6 million Dekatherms (Dth), or a 5.7 percent decrease from the prior year. Gas sales for the fiscal year ended March 31, 2004, excluding transportation of

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customer-owned gas, decreased approximately 3.6 million Dth, or a 5.3 percent decrease from the fiscal year ended March 31, 2003. The decreased gas usage for fiscal year ended March 31, 2005 as compared to fiscal year ended March 31, 2004 is partially due to impacts of weather and partially due to decreased use per customer as a result of customer response to higher natural gas prices. The decreased gas usage for fiscal year ended March 31, 2004 as compared to fiscal year ended March 31, 2003 is partially due to impacts of weather and partially due to migration of customers to alternate providers.

OPERATING EXPENSES

Purchased electricity decreased approximately $227 million for the year ended March 31, 2005 from the prior year. The volume of kWh purchased decreased 5.5 billion kWh (17% ) compared to the prior 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 2% increase in the price of electricity over the prior year.

Purchased electricity decreased approximately $3 million for the year ended March 31, 2004 from the prior year. Corresponding to lower electric sales, the Company purchased less kWh of electricity versus the prior year. In addition, contractual obligations to certain higher cost suppliers expired in fiscal year 2004, which resulted in a reduction to purchased power expense of $16 million, as compared to the prior year. However, increases in the market price of electricity substantially offset these decreases.

Purchased gas expense increased approximately $31 million for the year ended March 31, 2005 from the prior year. 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 in the year ended March 31, 2005 from $6.61 in the prior year. This increase in price was slightly offset by decreased purchases.

Purchased gas expense increased approximately $85 million for the year ended March 31, 2004 as compared to the fiscal year ended March 31, 2003. The increase is a result of higher gas prices in the fiscal year ended March 31, 2004 partially offset by decreased sales attributable to the warmer weather conditions than in the comparable prior period. The Company’s net cost per Dth, as charged to expense, including the effects of the gas cost deferral, increased to $6.61 for the year ended March 31, 2004 from $5.57 in the prior year ended March 31, 2003.

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

Other operation and maintenance expense decreased $84 million for the year ended March 31, 2005 from the prior year. The table below details components of this fluctuation.

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The decrease is mainly due to decreased retiree benefit expense of $54 million relating to one-time items. The pension settlement loss recovery of $14 million reflects the PSC July 2004 approval for the Company to recover a portion of the $30 million pension settlement loss incurred in fiscal 2003. The Company has petitioned the PSC for recovery of a $21 million pension settlement loss that was recorded to expense in the prior year. In fiscal 2004, the Company recorded a $19 million loss related to the non-union employee early retirement program (VERO). These pension items were recorded to expense by the Company, without a similar adjustment in the comparison period.

The reduction in bad debt expense for the year ended March 31, 2005, was mainly the result of a decrease in accounts receivable and improved collection practices.

The decrease in Other of $13 million for the year ended March 31, 2005, reflects ongoing reduced costs from merger-related efficiencies including staffing reductions and other decreased expenses.

Other operation and maintenance expense decreased $47 million for the year ended March 31, 2004 from the prior year. The decrease is primarily due to a $28 million decrease in bad debt expense and a recorded charge of $19 million to write-off certain projects in its construction work-in-process (CWIP) accounts recorded in the year ended March 31, 2003 with no comparable charge recorded in the year ended March 31, 2004. This charge was the result of a post-merger review of pre-merger CWIP projects.

Depreciation and amortization remained constant for the year ended March 31, 2005 from the prior year. For the year ended March 31, 2004, depreciation and amortization increased approximately $2 million from the prior year, primarily due to increased plant acquisitions.

Amortization of stranded costs increased $57 million and $45 million for the years ended March 31, 2005 and March 31, 2004, respectively, from the prior years in accordance with the Merger Rate Plan. Under the Merger Rate Plan (which became effective on January 31, 2002) 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.

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

Other taxes decreased approximately $26 million for the year ended March 31, 2004 from the prior year. This decrease is primarily due to a $31 million reduction of GRT as a result of lower GRT rates offset by increased property taxes of $9 million.

Income taxes increased $32 million for the year ended March 31, 2005 from the prior year primarily due to higher taxable income offset by a decrease related to a $20 million prior year accrual with no comparable accrual in the current year and an $8 million adjustment in the current year related to prior years’ state income tax. Income taxes increased $46 million for the year ended

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March 31, 2004 from the prior year primarily due to a $20 million accrual to return true-up and higher book taxable income.

OTHER INCOME (DEDUCTIONS), INTEREST AND PREFERRED DIVIDENDS

Other income (deductions) increased $16 million for the year ended March 31, 2005 from the prior year mainly due to a $9 million settlement of an estimated liability and a $8 million favorable adjustment to non-utility related income taxes.

Other income (deductions) decreased $6 million for the year ended March 31, 2004 from the prior year mainly due to an increase in expenses related to the Stock Appreciation Rights (SARs) program due to increases in the value of National Grid Transco’s stock price. See Item 8. Financial Statements and Supplementary Data — Note K — Stock Based Compensation, for more in formation on the Company’s SARs program.

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

Interest charges decreased $77 million for the year ended March 31, 2004 from the prior year. The decrease is primarily due to the early redemption of third-party debt using affiliated company debt at lower interest rates. In addition, the expiration of the Master Restructuring Agreement interest savings deferral in fiscal year 2004 contributed to the decrease. Also, in fiscal 2003 the Company recorded $8 million of interest expense related to a PSC staff adjustment concerning pension and other post-retirement benefits funding for which there was no corresponding charge in fiscal year 2004.

EFFECTS OF CHANGING PRICES

The Company is sensitive to 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 consolidated 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 with identical assets due to 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: At March 31, 2005, the Company’s principal sources of liquidity included cash and cash equivalents of $20 million and accounts receivable of $572 million. The Company has a negative working capital balance of $423 million primarily due to long-term debt due within one year of $550 million and short-term debt to affiliates of $401 million (see intercompany money

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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 for debt payments and other operating needs. As discussed below, the Company believes it has sufficient cash flow and borrowing capacity to fund such deficits as necessary in the near term.

     Net cash provided by operating activities increased approximately $536 million for the year ended March 31, 2005 from the prior year. The primary reasons for the increase in operating cash flow are:

•		Higher net income (see earnings discussion above) of approximately $124 million.
•		Higher stranded cost amortization of approximately $57 million.
•		Higher provision for deferred income taxes of approximately $32 million mainly attributable to net operating loss carryforwards.
•		Lower required funding of employee pension and other benefits of $156 million.
•		Increased regulatory liabilities and other deferred credits of $73 million.

The Company’s net cash used in investing activities decreased $55 million for the year ended March 31, 2005 from the comparable period in the prior year. This decrease was primarily a result of lower construction additions.

The Company’s net cash used in financing activities increased $594 million for the year ended March 31, 2005 from the comparable period in prior year. This increase results from an equity contribution from Holdings of $309 million in the prior year with no comparable contribution in the current year and an increase in the net payments of short term borrowings of $329 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. Construction expenditure levels for the energy delivery business are generally consistent from year-to-year.

The Company’s long-term debt due within one year is $550 million at March 31, 2005. In addition, construction expenditures planned within one year are estimated to be $240 million. These capital requirements are planned to be financed primarily from internally generated funds and borrowings from other National Grid USA companies through the intercompany money pool or directly.

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

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

In August 2003, the New York State PSC approved a settlement with the Company following an audit that identified reconciliation issues between the rate allowance and actual costs of the Company’s pension and other post-retirement benefits. The settlement resolved all issues associated with those obligations for the period prior to its acquisition by National Grid and, among other things, covered the funding of the Company’s pension and post-retirement benefit plans. As part of the settlement, the Company provided $100 million of tax-deductible funding by the end of fiscal 2003 and an additional $209 million of tax-deductible funding by fiscal 2004. Under the settlement, the Company will earn a rate of return of at least 6.60 percent (nominal) on the $209 million of funding through December 31, 2011 and is eligible to earn 80 percent of the amount by which the rate of return on the pension and post-retirement benefit funds exceeds 5.34 percent (nominal) measured as of that date.

In addition to the funding provided in respect of the settlement referred to above, other contributions to the pension and post-retirement trusts were lower in the current fiscal year than in the prior years. In the prior years, the Company funded certain early retirement program costs.

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 and 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.

Capital requirements are planned to be financed primarily from internally generated funds and borrowings from other National Grid USA companies through the money pool or directly. The Company also has the ability to issue first mortgage bonds to the extent that there have been maturities or early redemptions since June 30, 1998. Through March 31, 2005, the Company had approximately $1.9 billion in such first mortgage bond maturities and early redemptions. This is expected to increase to approximately $2.4 billion in 2007 based on scheduled maturities.

On May 27, 2004, the Company completed the refinancing of $115.7 million of tax exempt bonds, 7.2%, due 2029. The bonds were reissued in auction rate mode. These bonds were originally issued in 1994 to finance pollution control assets located at Nine Mile Point nuclear power station.

New Accounting Standards: On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act expands Medicare, primarily by adding a prescription drug benefit for those who are eligible for Medicare starting in 2006. The Act provides employers currently sponsoring prescription drug programs for Medicare-eligibles with a range of options for coordinating with the new government-sponsored program to potentially reduce program cost. These options include supplementing the government

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program on a secondary payor basis or accepting a direct subsidy from the government to support a portion of the cost of the employer’s program.

Paragraph 40 of the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standard (SFAS) No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” requires that presently enacted changes in laws affecting employer-sponsored retiree health care programs which take effect in future periods be considered in current-period measurements for benefits expected to be provided in those future periods. Therefore, under FAS 106 guidance, measures of plan liabilities and annual expense on or after the date of enactment should reflect the effects of the Act. Pursuant to guidance from the FASB under FSP FAS 106-2, the retiree health obligations will reflect the estimated subsidy payments expected from the federal government for the participant groups anticipated to qualify for the subsidy. Participant groups who are not expected to qualify, or have not yet been determined whether they will qualify, for the federal subsidy will not affect the retiree health obligations. If any portion of this group is subsequently determined to qualify for the subsidy, the retiree health care obligations will be adjusted at the time of that determination. The Company has chosen to apply the guidance prospectively, impacting retiree health costs. The Company adopted the provisions of FAS 106-2 on July 1, 2004. Any decrease in expense that results from the Act will be deferred and will be credited to customers. See Note H – Employee Benefits.

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” This Standard 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. This Standard also eliminates the ability to account for share-based compensation transactions using Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and requires that such transactions be accounted for using a fair-value-based method. The Standard is effective for periods beginning after June 15, 2005. The Company does not anticipate that adoption of SFAS 123R will have a material impact on its results of operations or its financial position.

In March 2005, FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). 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.

FIN 47 clarifies that the term conditional asset retirement obligation as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations”, 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 entity. The obligation to perform the asset retirement activity is unconditional even though the uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

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This statement will be effective for the fiscal year ended March 31, 2006 for the Company. The adoption of FIN 47 is not expected to have a material impact on the Company’s results of operations or its financial position.

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:

	§		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 these risks. This committee issues and oversees the Financial Risk Management Policy which outlines the parameters within which corporate managers are to engage in, manage and report on various areas of 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.

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. During the fiscal year ended March 31, 2005, the Company converted $115.7 million of fixed-rate long term debt to adjustable rate promissory notes. Total adjustable rate promissory notes are currently valued at $575 million. In December 2004 the Company redeemed the remaining $25.2 million of Cumulative Fixed/Adjustable Preferred Stock, Series D. There was $400.5 million of short term borrowing at March 31, 2005 from the inter-company money pool maintained by National Grid. At March 31, 2004 these borrowings totaled $463.5 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, 2005 and 2004, adjustable rate instruments comprise 19.7 percent and 13.2 percent of total long term debt, respectively. The proportion of adjustable instruments to total capitalization increased because of the conversion of $115.7 million of fixed-rate debt to variable-rate debt. In the aggregate at March 31, 2005 and 2004 variable rate instruments do not

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constitute a significant portion of total capitalization and debt, thus limiting the Company’s exposure to interest rate fluctuations.

If interest rates averaged 1 percent more in the next fiscal year versus 2005, the Company’s interest expense would increase and income before taxes would decrease by approximately $9.75 million. This figure was derived by applying a hypothetical 1 percent variance to the variable rate debt of $575.0 million plus the short-term variable borrowings of $400.5 million at March 31, 2005. 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.

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 in order to mitigate expected price volatility but only to the extent that quantities 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 upon 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 $619 million and $715 million at March 31, 2005 and 2004, respectively, and is recorded on the Company’s balance sheets as a “Liability for swap contracts.” The decrease is primarily due to revaluation of the contracts at March 31, 2005, in addition to normal contract settlements, partially offset by a lowering of the discount rate. The discount rate is a market-based rate representing the yield curve through the life of the contracts. Based upon the PSC’s approval of the restated contracts, including the indexed swap contracts, as part of the MRA and being provided a reasonable opportunity to recover the estimated indexed swap liability from customers, the Company has recorded a corresponding regulatory asset. The amounts of the recorded liability and regulatory asset are sensitive to changes in anticipated future market prices and changes in the indices upon which the indexed swap contract payments are based.

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If the indexed contract price were to increase or decrease by 1 percent, the Company would see a $12.1 million increase or decrease in the present value of the projected over-market exposure associated with these contracts. If the market prices were to increase or fall by 1 percent, the Company would see a $5.9 million decrease or increase in the projected over-market exposure associated with these contracts. If the discount rate were one half percent higher or lower, the net present value of the projected over market exposure associated with these contracts would decrease or increase by approximately $5.1 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 pays 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, 2005, gas futures have been purchased to hedge approximately 50 percent of the amount needed to offset gas price changes in the period ended March 31, 2006.

At March 31, 2004, the open NYMEX futures the Company had in place to hedge the payments under these contracts had a fair value gain of $20.2 million.

Activity for the fair value of the NYMEX futures and gas basis swaps for the 12 months ended March 31, 2005, is as follows:

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 Financial Risk Management Policy and is monitored by the EPRMC.

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The Company attempts to hedge approximately 50 percent of its forecasted average demand for the October to April period through a program using in-ground storage and financial instruments. The Company uses NYMEX gas futures. Each NYMEX futures contract represents 10,000 Dth of gas. At March 31, 2004 the mark to market net open position of cash flow hedges for gas supply was a gain of $4.1 million. There were 453 open futures contracts at March 31, 2004.

The following table details the fair value activity for gas cash flow hedges for the 12 months ended March 31, 2005:

The above activity coupled with the in-ground storage hedged approximately 50 percent 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, 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, 2005, the mark to market net open position of electricity swap contracts was a gain of $1.1 million.

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

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

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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, 2005.
	•		Consolidated Balance Sheets at March 31, 2005 and 2004.
	•		Consolidated Statements of Cash Flows for each of the three years in the period ended March 31, 2005.
	•		Notes to Consolidated Financial Statements.

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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 presents fairly, in all material respects, the financial position of Niagara Mohawk Power Corporation and its subsidiaries at March 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2005 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 accompanying index 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.

Boston, Massachusetts
May 18, 2005

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

Consolidated Statements of Comprehensive Income
(In thousands of dollars)

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.

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NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Statements of Retained Earnings
(In thousands of dollars)

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)

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

29

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
(In thousands of dollars)

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

30

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

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

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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.

The Company is a wholly-owned subsidiary of Niagara Mohawk Holdings, Inc. (Holdings), which in turn is wholly-owned by National Grid USA (National Grid).

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.

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 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

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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, 2005 and 2004 were 1.59 percent and 1.22 percent, 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:

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:

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 both March 31, 2005 and 2004 was approximately $110 million and $123 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 (ended December 2004 with the Company having the right to request an increase at any time, if needed), changes in accrued unbilled gas revenues are deferred. At March 31, 2005 and 2004, approximately $7 million and $9 million, respectively, of unbilled gas revenues remain unrecognized in results of operations. The Company cannot predict when unbilled gas revenues will be allowed to be recognized in results of operations.

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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 continue to 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 an increase 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 operating pursuant to the provisions of Section 13 of the Public Utility Holding Company Act of 1935, has furnished services to the Company at the cost of such services since the merger with National Grid. These costs approximated $138 million and $113 million for the years ended March 31, 2005 and 2004, 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 deposit.

Derivatives: The Company accounts for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (FAS 133), and SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” as amended. Under the provisions of FAS 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 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

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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 additional minimum pension liability recognition, 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 does not recognize its additional minimum pension liability (AML) for its qualified plan as a component of accumulated other comprehensive income but as a regulatory asset. The additional minimum pension liability for its non-qualified plan is recognized in accumulated other comprehensive income.

Power Purchase Agreements: The Company accounts for its power purchase agreements as executory contracts. The Company assesses several factors in determining how to account for its power purchase contracts. These factors include:

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

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

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

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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: On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act expands Medicare, primarily by adding a prescription drug benefit for those who are eligible for Medicare starting in 2006. The Act provides employers currently sponsoring prescription drug programs for Medicare-eligibles with a range of options for coordinating with the new government-sponsored program to potentially reduce program cost. These options include supplementing the government program on a secondary payor basis or accepting a direct subsidy from the government to support a portion of the cost of the employer’s program.

Paragraph 40 of the FASB’s SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” requires that presently enacted changes in laws affecting employer-sponsored retiree health care programs which take effect in future periods be considered in current-period measurements

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for benefits expected to be provided in those future periods. Therefore, under FAS 106 guidance, measures of plan liabilities and annual expense on or after the date of enactment should reflect the effects of the Act. Pursuant to guidance from the FASB under FSP FAS 106-2, the retiree health obligations will reflect the estimated subsidy payments expected from the federal government for the participant groups anticipated to qualify for the subsidy. Participant groups who are not expected to qualify, or have not yet been determined whether they will qualify, for the federal subsidy will not affect the retiree health obligations. If any portion of this group is subsequently determined to qualify for the subsidy, the retiree health care obligations will be adjusted at the time of that determination. The Company has chosen to apply the guidance prospectively, impacting retiree health costs. The Company adopted the provisions of FAS 106-2 on July 1, 2004. Any decrease in expense that results from the Act will be deferred and will be credited to customers. See Note H – Employee Benefits.

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” This Standard 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. This Standard also eliminates the ability to account for share-based compensation transactions using Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and requires that such transactions be accounted for using a fair-value-based method. The Standard is effective for periods beginning after June 15, 2005. The Company does not anticipate that adoption of SFAS 123R will have a material impact on its results of operations or its financial position.

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). 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.

FIN 47 clarifies that the term conditional asset retirement obligation as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations”, 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 entity. The obligation to perform the asset retirement activity is unconditional even though the uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

This statement will be effective for the fiscal year ended March 31, 2006 for the Company. The adoption of FIN 47 is not expected to have a material impact on the Company’s results of operations or its financial position.

Reclassifications: Certain amounts from prior years have been reclassified on the accompanying consolidated financial statements to conform to the fiscal 2005 presentation.

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NOTE B – RATE AND REGULATORY ISSUES

The Company’s financial statements conform to GAAP, including the accounting principles for rate-regulated entities with respect to its regulated operations. Substantively, SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (FAS 71) permits a public utility, regulated on a cost-of-service basis, to defer certain costs, which would otherwise be charged to expense, when authorized to do so by the regulator. These deferred costs are known as regulatory assets, which in the case of the Company, are approximately $5 billion and $5.2 billion at March 31, 2005 and 2004, respectively. These regulatory assets are probable of recovery under the Company’s Merger Rate Plan and Gas Multi-Year Rate and Restructuring Agreement. The Company believes that the regulated cash flows to be derived from prices it will charge for electric service in the future, including the Competitive Transition Charges (CTCs), and assuming no unforeseen reduction in demand or bypass of the CTC or exit fees, will be sufficient to recover the Merger Rate Plan stranded regulatory assets over the planned amortization period with a return. Under the Merger Rate Plan, the Company’s remaining electric business (electricity transmission and distribution business) continues to be rate-regulated on a cost-of-service basis and, accordingly, the Company continues to apply FAS 71 to these businesses. Also, the Company’s Independent Power Producer (IPP) contracts and the Purchase Power Agreements (PPAs) entered into in connection with the generation divestiture 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 FAS 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 FAS 71, the resulting charge would be material to the Company’s reported financial condition and results of operations.

Under the Merger Rate Plan, the Company is earning a return on most of its regulatory assets.

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 January 31, 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 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

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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. As a result of the closing of the merger, the Company revalued its assets and liabilities, which resulted in an increase to the Company’s postretirement liability of approximately $440 million.

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

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 as interest expense ratably 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 H, D and L for a discussion of regulatory asset accounts — Pensions and postretirement benefits Plans, Deferred environmental restoration costs and Swap contracts regulatory asset, respectively.

NOTE C – ACCUMULATED OTHER COMPREHENSIVE INCOME

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Taxes on other comprehensive income for the following periods were:

NOTE D – COMMITMENTS AND CONTINGENCIES

Commodity Reconciliations: As part of the Company’s ongoing reconciliation of commodity costs and revenues, the Company identified several adjustments for the period from October 1, 2001 through April 30, 2003, and included them in filings with the PSC. Specifically, the Company requested recovery of $36 million of commodity costs associated with the under-reconciliation of New York Power Authority (NYPA) hydropower revenues in its commodity adjustment clause, and proposed to refund $24 million associated with other revenues that were not included in the commodity adjustment reconciliation. Following the filing, the PSC Staff completed a comprehensive audit of the Company’s commodity costs and revenues from October 1, 2001 through December 31, 2003, and the Staff and the Company agreed that a refund of $2.8 million should be provided to customers through that period. The PSC approved the refund on December 20, 2004.

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, 2005 are summarized in the table below. The Company did not enter into any new agreements in fiscal 2005 or 2004. 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.

If the Company needs any additional energy to meet its load it can purchase the electricity from other IPPs, other utilities, other 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.

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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, 2005, for the next five years, and thereafter.

With respect to firm gas supply commitments, the amounts are based upon volumes specified in the contracts giving consideration for 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 at current filed tariffs. At March 31, 2005, the Company’s firm gas supply commitments have varying expiration dates, the latest of which is November 2006. 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 Niagara Mohawk are subject to various federal, state and local environmental laws and regulations. Like most other industrial companies, our transmission and distribution companies use or generate some hazardous and potentially hazardous wastes and by-products. Under federal and state Superfund laws, potential liability for the historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.

The Environmental Protection Agency (EPA), Department of Environmental Conservation (DEC), as well as private entities have alleged that Niagara Mohawk is a potentially responsible party under state or federal law for the remediation of an aggregate of approximately 100 sites, including 56 which are Company owned. Our most significant liabilities relate to former manufactured gas plant (MGP) facilities formerly owned or operated by our predecessors. Niagara Mohawk is currently investigating and remediating, as necessary, those MGP sites and certain other properties under agreements with the EPA and DEC.

We believe that our ongoing operations, and our approach to addressing conditions at historic sites, are in substantial compliance with all applicable environmental laws, and that the obligations imposed on us are not likely to have a material adverse impact on our financial condition, results of operations or cash flows. The Merger Rate Plan provides for the continued application of deferral accounting for variations

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in spending from amounts provided in rates. The Company has recorded a regulatory asset representing the investigation, remediation and monitoring obligations to be recovered from ratepayers.

We are pursuing claims against potentially responsible parties to recover investigation and remediation costs, but we cannot predict the success of such claims. As of March 31, 2005 and 2004, the Company has accrued a liability in the amount of $431 million and $309 million, respectively, which is reflected in the Company’s Consolidated Balance Sheets. The increase in the liability follows a recent review and reflects experience by the National Grid Companies in restoring similar sites. The potential high end of the range at March 31, 2005 is presently estimated at approximately $558 million.

Nuclear Contingencies: As of March 31, 2005 and 2004, the Company has a liability of $146 million and $143 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, who 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:

Retail Bypass: 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 Niagara Mohawk’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 involving affiliates of NRG Energy, Inc. is discussed below. These orders directly conflict with Niagara Mohawk’s state-approved tariffs and the orders of the PSC on station service rates. The December 2003 FERC orders, if upheld, will permit these generators to bypass Niagara Mohawk’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. Niagara Mohawk filed for rehearing of these orders, and the FERC denied these requests in January 2005. Niagara Mohawk has appealed the December 2003 and January 2005 orders to the U.S. Court of Appeals for the District of Columbia Circuit.

In an order dated May 10, 2004, in a related proceeding concerning the NYISO, the FERC reaffirmed its reasoning of the December 2003 orders. In so ruling, the FERC indicated that the NYISO station service order would be limited to merchant generators self-supplying their own power, and should not be interpreted to apply to self-supplying retail industrial and commercial customers that do not compete with incumbent utilities for customer load. The Company appealed the order to the Court of Appeals for the District of Columbia Circuit on July 9, 2004.

These recent FERC orders have increased the risk that generators will be able to bypass local distribution company charges (including stranded cost recovery charges) when receiving service through

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the NYISO. Although subject to review by the PSC Staff and other parties, the Company believes that if it experiences any lost revenue attributable to retail bypass, it will be permitted to recover these lost revenues under its Merger Rate Plan.

Niagara Mohawk Power Corp. v. Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C. The Company previously owned three power plants (the Plants), which it sold to three affiliates of NRG Energy, Inc. in 1999: Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C. (collectively, the NRG Affiliates). The Company is in involved in several proceedings with the NRG Affiliates to recover bills for station service rendered to the Plants.

The most significant is a proceeding at FERC involving Niagara Mohawk’s complaint against the NRG Affiliates for failure to pay station service charges the Company assessed under its state-approved retail tariffs. A state collection action and other proceedings have all been stayed pending the outcome of the FERC proceeding. As of March 31, 2005, the NRG Affiliates owed Niagara Mohawk approximately $43.5 million for station service. On November 19, 2004 and April 22, 2005, the FERC issued orders denying Niagara Mohawk’s complaint and found that the NRG Affiliates do not have to pay state-approved retail rates for station service. Niagara Mohawk has appealed the orders to the US Court of Appeals for the District of Columbia Circuit. The Court has consolidated this appeal with the two retail bypass cases discussed above. Although subject to review by the PSC Staff and other parties, the Company believes that if the Court were to uphold the FERC’s orders, the Company will be permitted to recover under its rate plans the station service charges not paid by the NRG Affiliates.

New York ISO Mitigation Error: On March 4, 2005, FERC issued an order on remand from the U.S. Court of Appeals for the District of Columbia Circuit (PSEG Energy Resource & Trade LLC v. New York Independent System Operator, FERC Docket No. EL02-16; H.Q. Energy Services, Inc. v. New York Independent System Operator, FERC Docket No. EL01-19). In this case, the New York Independent System Operator (NYISO) had “mitigated”, or retroactively reduced, bid prices of approximately $3,500 per megawatt-hour to about $300 per megawatt-hour during a period of several hours on May 8 and 9, 2000. FERC had approved the NYISO’s action, but the Court of Appeals reversed FERC. On remand, FERC reinstated the original higher market prices. Although the NYISO has asked for more time to determine the unmitigated prices, management currently estimates the Company’s exposure for increased power supply costs during those two days to range between $7 and $10 million, with interest.

NOTE E – LONG-TERM DEBT

Long-term debt consisted of the following:

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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 and Promissory Notes 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 $414 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 would require the Company to issue First Mortgage Bonds to secure the debt) which averaged 1.69 percent for the year ended March 31, 2005, 1.24 percent for the year ended March 31, 2004, 1.36 percent for the year ended March 31, 2003 and are supported by bank direct pay letters of credit. 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 (see Note F).

On May 1, 2003, the Company completed the restructuring of $414 million of variable rate tax-exempt bonds. The bonds are currently in the auction rate mode and are backed by bond insurance, which allowed the Company to terminate $424 million of letter of credit facilities that were in place to provide liquidity support for principal and interest while the bonds were in a variable rate mode. The restructuring of the $414 million of tax-exempt bonds was accomplished through a non-cash transaction.

The aggregate maturities of long-term debt for the five years subsequent to March 31, 2005, excluding capital leases are approximately:

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