UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


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

For the fiscal year ended March 31, 2005


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

For the transition period___________to______________


Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address and Telephone Number	Identification Number

1-2987	Niagara Mohawk Power Corporation	15-0265555
	(a New York corporation)
	300 Erie Boulevard West
	Syracuse, New York 13202
	315.474.1511

Securities registered pursuant to Section 12(b) of the Act:

(Each class is registered on the New York Stock Exchange)


Registrant		Title and Class

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

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

Indicate by check mark 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.


Registrant	Title	Shares Outstanding at June 27, 2005

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

NIAGARA MOHAWK POWER CORPORATION

TABLE OF CONTENTS


		PAGE
	PART I

Item 1.	Business		4
Item 2.	Properties		6
Item 3.	Legal Proceedings		7
Item 4.	Submission of Matters to a Vote of Security Holders		7

	PART II

Item 5.	Market for the Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchases of Equity Securities		8
Item 6.	Selected Consolidated Financial Data		8
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		9
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		21
Item 8.	Financial Statements and Supplementary Data		25
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		61
Item 9A.	Controls and Procedures		61
Item 9B.	Other Information		62

	PART III

Item 10.	Directors and Executive Officers of the Registrant		62
Item 11.	Executive Compensation		64
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		70
Item 13.	Certain Relationships and Related Transactions		70
Item 14.	Principal Accountant Fees and Services		70

	PART IV

Item 15.	Exhibits and Financial Statement Schedules		71

Signatures			74
EX-10(i)
EX-10(j)
EX-10(l)
EX-10(m)
Ex-10(n)
EX-10(o)
EX-10(p)
EX-10(r)
EX-10(u)
EX-10(v)
EX-21
EX-31.1
EX-31.2
EX-32

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).

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.

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

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

	•		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,

	•		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.


							60 Day		30 Day			Three
							Period		Period			months
	Year Ended		Year Ended		Year Ended		Ended		Ended			Ended
	March 31,		March 31,		March 31,		March 31,		January 30,			March 31,		Year Ended December 31,
(in 000’s except	2005		2004		2003		2002		2002			2001		2001		2000
Per share data)	(Successor)		(Successor)		(Successor)		(Successor)		(Predecessor)			(Predecessor)		(Predecessor)		(Predecessor)
Operating revenues	$	3,925,171	$	4,063,617	$	4,019,450	$	689,705	$	362,622		$	1,179,706	$	4,114,713	$	3,865,949

Net income (loss)		263,249		139,690		125,871		30,646		(20,941	)		34,010		19,358		(27,646	)

Income (loss) from		*		*		*		*		*			*		*		*
continuing operations per average common share

60 Day

30 Day

Three

Period

months

Year Ended

Year Ended

Ended

March 31,

March 31,

January 30,

March 31,

Year Ended December 31,

(in 000’s except

2005

2004

2003

2002

2001

2000

Per share data)

(Successor)

(Successor)

(Predecessor)

Total assets

12,518,362

12,618,659

12,549,865

12,101,588

12,037,039

11,436,554

12,270,324

Long-term debt

2,923,569

3,473,467

3,953,989

4,146,642

4,674,004

4,419,822

4,678,963

Mandatorily redeemable

—

53,750

50,700

53,750

preferred stock

Dividends paid per

common share

*		All of the Company’s shares of common stock are owned by its parent company. Therefore, management considers dividend information and per share data are not relevant.

**		Balance Sheet information as of the 30 day period ended January 30, 2002 is not provided.

ITEM 7.

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

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

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

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

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

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.


Change in Electric Revenue for the fiscal year ended
($ in millions)	March 31, 2005			March 31, 2004

Retail sales	$	(98	)	$	(153	)
Delivery only sales and miscellaneous revenue		20			99
Sales for resale		(89	)		27

Total	$	(167	)	$	(27	)

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

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.


Change in kWh Deliveries for the fiscal year ended
(kWh in millions)	March 31, 2005			March 31, 2004

Retail sales		(1.4	)		(2.3	)
Delivery only sales		1.6			2.0

Total deliveries to ultimate customers		0.2			(0.3	)
Sales for resale		(2.1	)		0.2

Total deliveries		(1.9	)		(0.1	)

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:


Change in Gas Revenue for the fiscal year ended
($’s in Millions)	March 31, 2005			March 31, 2004

Cost of Purchased Gas	$	31		$	85
Delivery Revenue		(4	)		3
Other		1			(17	)

Total	$	28		$	71

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

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.


	For the year			For the year
	ended			Ended
($’s in millions)	March 31, 2005			March 31, 2004		Change

Bad debt expense		45			64		(19	)
VERO expense		—			19		(19	)
Recovery of 2003 pension settlement loss		(14	)		—		(14	)
Pension settlement loss		—			21		(21	)
April 2003 ice storm		—			6		(6	)
Loss on sale of facilities		8			—		8
Other		670			683		(13	)

Total	$	709		$	793	$	(84	)

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

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

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:



	Contractual obligations due in
			Less than		1 - 3		4 - 5
($’s in Millions)	Total		one year		years		years		Thereafter

Long-term debt	$	3,475	$	550	$	475	$	950	$	1,500
Short-term debt due to affiliates*		401		401		—		—		—
Interest on long-term debt**		633		182		271		180		N/A
Electric purchase power commitments		4,505		437		848		750		2,470
Gas supply commitments		450		255		165		11		19
Derivative swap commitments***		619		204		379		36		—
Construction expenditures****		240		240		N/A		N/A		N/A

Total contractual cash obligations	$	10,323	$	2,269	$	2,138	$	1,927	$	3,989

Classified as a current liability as all borrowings are payable on demand.

**		Forecasted, actual amounts could differ based on changes in market conditions. Amounts beyond 5 years are not forecasted and are therefore not included.

***		Forecasted, actual amounts could differ based on changes in market conditions.

****		Budgeted amount in which substantial commitments have been made. Amounts

		beyond 1 year are budgetary in nature and not considered contractual obligations

		and are therefore not included.

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

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.

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

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.

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:



	*Hedges of IPP Swaps*						*Hedges Non-MRA IPP*
(in thousands of dths and dollars)	NYMEX Futures						NYMEX Futures
	Dth			Fair Value			Dth			Fair Value

March 31, 2004 asset		20,210.0		$	18,803.4			1,640.0		$	1,500.2
New contracts		40,783.7			—			3,216.3			—
Settled during period		(40,946.8	)		(19,449.6	)		(3,263.2	)		(1,602.6	)
Mark-to-market adjustments		—			25,659.7			—			2,108.5

March 31, 2005 asset		20,046.9		$	25,013.5			1,593.1		$	2,006.1

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.

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:


*Hedges of Gas Supply*
	NYMEX Futures
(in thousands of dths and dollars)	Dth			Fair Value

March 31, 2004 asset		4,640.0		$	4,089.3
New Contracts		10,260.0			—
Settled during the period		(8,970.0	)		(9,947.2	)
Mark-to-market adjustments					13,091.3

March 31, 2005 asset		5,930.0		$	7,233.4

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.

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.

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.


/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Boston, Massachusetts
May 18, 2005

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



	For the		For the			For the
	year ended		year ended			year ended
	March 31,		March 31,			March 31,
	2005		2004			2003

Operating revenues:
Electric	$	3,117,156	$	3,284,017		$	3,310,837
Gas		808,015		779,600			708,613

Total operating revenues		3,925,171		4,063,617			4,019,450

Operating expenses:
Purchased electricity		1,364,813		1,591,652			1,594,221
Purchased gas		509,543		478,647			393,796
Other operation and maintenance		708,606		793,110			840,367
Depreciation and amortization		200,793		200,650			198,253
Amortization of stranded costs		251,499		194,114			149,415
Other taxes		217,993		227,006			253,207
Income taxes		171,230		138,843			93,277

Total operating expenses		3,424,477		3,624,022			3,522,536

Operating income		500,694		439,595			496,914


Other income (deductions)		8,347		(7,198	)		(1,340	)

Operating and other income		509,041		432,397			495,574

Interest:
Interest on long-term debt		169,585		220,781			318,149
Interest on debt to associated companies		66,283		55,282			16,852
Other interest		9,924		16,644			34,702

Total interest expense		245,792		292,707			369,703

Net income		263,249		139,690			125,871

Dividends on preferred stock		2,928		4,430			5,568

Income available to common shareholder(s)	$	260,321	$	135,260		$	120,303

Consolidated Statements of Comprehensive Income
(In thousands of dollars)


	For the		For the			For the
	year ended		year ended			year ended
	March 31,		March 31,			March 31,
	2005		2004			2003

Net income	$	263,249	$	139,690		$	125,871
Other comprehensive income (loss):
Unrealized gains (losses) on securities, net of tax		559		1,731			(710	)
Hedging activity, net of tax		9,787		2,425			600
Additional minimum pension liability		—		(1,557	)		—

Total other comprehensive income (loss)		10,346		2,599			(110	)

Comprehensive income	$	273,595	$	142,289		$	125,761

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.

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



	For the			For the			For the
	year ended			year ended			year ended
	March 31,			March 31,			March 31,
	2005			2004			2003
Retained earnings at beginning of period	$	220,966		$	85,706		$	29,317
Net income		263,249			139,690			125,871
Dividends on preferred stock		(2,928	)		(4,430	)		(5,568	)
Dividend to Niagara Mohawk Holdings, Inc.		(8,000	)		—			(63,914	)

Retained earnings at end of period	$	473,287		$	220,966		$	85,706

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

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



	March 31,		March 31,
	2005		2004

ASSETS
Utility plant, at original cost:
Electric plant	$	5,347,832	$	5,200,640
Gas plant		1,517,804		1,477,977
Common plant		330,437		333,789
Construction work-in-progress		69,702		152,821

Total utility plant		7,265,775		7,165,227

Less: Accumulated depreciation and amortization		2,108,379		2,078,328

Net utility plant		5,157,396		5,086,899

Goodwill		1,224,025		1,225,742
Pension intangible		40,339		10,990
Other property and investments		55,048		57,273
Current assets:
Cash and cash equivalents		19,922		26,840
Restricted cash (Note A)		7,367		12,163
Accounts receivable (less reserves of $126,085 and $124,200, respectively, and includes receivables from associated companies of $6,654 and $516, respectively)		571,552		578,654
Materials and supplies, at average cost:
Gas storage		3,498		11,226
Other		17,739		15,714
Derivative instruments (Note A and L)		35,326		24,393
Prepaid taxes		44,273		61,769
Current deferred income taxes (Note G)		307,431		273,135
Regulatory asset – swap contracts		203,558		182,000
Other		9,772		13,389


Total current assets		1,220,438		1,199,283

Regulatory and other non-current assets:
Regulatory assets (Note B):
Merger rate plan stranded costs		2,765,392		3,019,597
Swap contracts regulatory asset		415,394		533,367
Regulatory tax asset		79,933		151,080
Deferred environmental restoration costs		431,000		309,000
Pension and postretirement benefit plans		501,358		466,789
Additional minimum pension liability		194,302		157,068
Loss on reacquired debt		67,162		74,993
Other		330,094		288,427

Total regulatory assets		4,784,635		5,000,321

Other non-current assets		36,481		38,151

Total regulatory and other non-current assets		4,821,116		5,038,472

Total assets	$	12,518,362	$	12,618,659

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

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


	March 31,		March 31,
	2005		2004

CAPITALIZATION AND LIABILITIES
Capitalization:
Common stockholder’s equity:
Common stock ($1 par value)	$	187,365	$	187,365
Authorized - 250,000,000 shares
Issued and outstanding - 187,364,863 shares
Additional paid-in capital		2,929,501		2,929,501
Accumulated other comprehensive income		12,961		2,615
Retained earnings		473,287		220,966

Total common stockholder’s equity		3,603,114		3,340,447
Preferred equity (Note I):
Cumulative preferred stock ($100 par value, optionally redeemable)		41,170		41,170
Authorized - 3,400,000 shares
Issued and outstanding - 411,715 shares
Cumulative preferred stock ($25 par value, optionally redeemable)		—		25,155
Authorized - 19,600,000 shares
Issued and outstanding – 0 and 503,100 shares, respectively
Long-term debt (Note E)		1,723,569		2,273,467
Long-term debt to affiliates (Note E)		1,200,000		1,200,000

Total capitalization		6,567,853		6,880,239

Current liabilities:
Accounts payable (including payables to associated companies of $36,440 and $42,485, respectively)		271,275		285,965
Customers’ deposits		26,900		26,133
Accrued interest		82,945		98,221
Short-term debt to affiliates (Note F)		400,500		463,500
Current portion of liability for swap contracts (Note A and L)		203,558		182,000
Current portion of long-term debt (Note E)		550,420		532,620
Other		107,871		125,461

Total current liabilities		1,643,469		1,713,900

Non-current liabilities:
Accumulated deferred income taxes (Note G)		1,711,630		1,551,223
Liability for swap contracts (Note A and L)		415,394		533,367
Employee pension and other benefits (Note H)		434,855		449,803
Liability for environmental remediation costs		431,000		309,000
Nuclear fuel disposal costs		145,562		143,265
Additional minimum pension liability		236,198		169,615
Cost of removal regulatory liability (Note O)		318,455		313,545
Other		613,946		554,702

Total other non-current liabilities		4,307,040		4,024,520


Commitments and contingencies (Note D)		—		—


Total capitalization and liabilities	$	12,518,362	$	12,618,659

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

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



	Year			Year			Year
	ended			ended			ended
	March 31,			March 31,			March 31,
	2005			2004			2003

Operating activities:
Net income	$	263,249		$	139,690		$	125,871
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		200,793			200,650			198,253
Amortization of stranded costs		251,499			194,114			149,415
Provision for deferred income taxes		180,722			148,435			123,950
Pension and other benefit plans expense		100,143			100,484			59,955
Cash paid to pension and postretirement benefit plan trusts		(109,330	)		(266,139	)		(178,969	)
Changes in operating assets and liabilities:
Net accounts receivable		7,102			(35,374	)		(15,493	)
Materials and supplies		5,703			(5,744	)		(377	)
Accounts payable and accrued expenses		(31,513	)		(74,946	)		143,015
Accrued interest		(15,276	)		(10,706	)		(2,588	)
Other, net		31,898			(41,093	)		9,281

Net cash provided by operating activities		884,990			349,371			612,313

Investing activities:
Construction additions		(266,012	)		(317,302	)		(244,814	)
Proceeds from the sale of generation assets		—			—			249,799
Change in restricted cash		4,796			13,187			(17,268	)
Other investments		2,651			6,563			1,256
Other, net		(1,640	)		(17,294	)		(17,678	)

Net cash used in investing activities		(260,205	)		(314,846	)		(28,705	)

Financing activities:
Dividends paid on preferred stock		(2,928	)		(4,430	)		(5,568	)
Dividends paid on common stock to Holdings (including a return of capital of $86.1 million for fiscal year 2003)		(8,000	)		—			(150,000	)
Reductions in long-term debt		(532,620	)		(1,319,490	)		(668,675	)
Proceeds from long-term debt		—			45,600			—
Proceeds from long-term debt to affiliates		—			700,000			500,000
Redemption of preferred stock		(25,155	)		(33,903	)		(2,131	)
Net change in short-term debt to affiliates		(63,000	)		265,500			(221,000	)
Equity contribution from parent		—			309,000			—
Other, net		—			—			(16,078	)

Net cash used in financing activities		(631,703	)		(37,723	)		(563,452	)


Net increase (decrease) in cash and cash equivalents		(6,918	)		(3,198	)		20,156
Cash and cash equivalents at beginning of period		26,840			30,038			9,882

Cash and cash equivalents at end of period	$	19,922		$	26,840		$	30,038


Supplemental disclosures of cash flow information:

Interest paid	$	258,735		$	336,147		$	336,102
Income taxes paid (received)	$	(54,940	)	$	(13,904	)	$	13,279

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

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

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:


	Year Ended		Year Ended			Year Ended
	March 31,		March 31,			March 31,
	2005		2004			2003
($ in 000’s)
Other income (deductions)	$	1	$	(9	)	$	187
Other interest		606		565			384

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

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


	Year Ended		Year Ended		Year Ended
	March 31,		March 31,		March 31,
	2005		2004		2003

Asset Category:
Electric		35		34		34
Gas		43		44		42
Common		21		17		17

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

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

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:

•

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

•

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

•

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

•

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

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

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 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.

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

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

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


	Unrealized			Additional					Total
	Gains and			Minimum					Accumulated
	Losses on			Pension					Other
	Available-for-			Liability			Cash Flow		Comprehensive
($ in 000’s)	Sale Securities			Adjustment			Hedges		Income
March 31, 2003	$	(584	)	$	—		$	600	$	16
Unrealized gains (losses) on securities, net of taxes		1,731								1,731
Hedging activity, net of taxes								2,425		2,425
Change in additional minimum pension liability					(1,557	)				(1,557	)

March 31, 2004	$	1,147		$	(1,557	)	$	3,025	$	2,615

Unrealized gains on securities, net of taxes		559								559
Hedging activity, net of taxes								9,787		9,787


March 31, 2005	$	1,706		$	(1,557	)	$	12,812	$	12,961

Taxes on other comprehensive income for the following periods were:


	For the		For the year		For the
	year ended		ended		year ended
	March 31,		March 31,		March 31,
($ in 000’s)	2005		2004		2003

Unrealized gain/(losses) on securities	$	373	$	1,154	$	758
Hedging activities		6,524		1,617		(452	)

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.


(In thousands of dollars)
Fiscal Year
Ended	Estimated
March 31,	Payments

2006	$	437,266
2007		430,807
2008		416,889
2009		408,397
2010		342,060
Thereafter		2,470,043

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.

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.


(In thousands of dollars)
Fiscal Year
Ended			Gas Storage/
March 31,	Gas Supply		Pipeline

2006	$	198,056	$	56,919
2007		60,070		53,660
2008		—		51,713
2009		—		5,310
2010				5,310
Thereafter		—		19,266

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

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

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:


($ in 000’s)
			March 31,		March 31,			March 31,		March 31,
Series	Due		2005		2004		Series	2005		2004

First Mortgage Bonds:							Promissory Notes ⁽³⁾:
8%		2004	$	—	$	232,425	2015	$	100,000	$	100,000
6 5/8%		2005		110,000		110,000	2023		69,800		69,800
9 3/4%		2005		137,981		137,981	2025		75,000		75,000
7 3/4%		2006		275,000		275,000	2026		50,000		50,000
6 5/8%⁽¹⁾		2013		45,600		45,600	2027		25,760		25,760


($ in 000’s)
			March 31,		March 31,			March 31,			March 31,
Series	Due		2005		2004		Series	2005			2004

5.15%		2025		75,000		75,000	2027		93,200			93,200

7.2%⁽²⁾		2029		115,705		115,705	Total Promissory Notes		413,760			413,760

Total First Mortgage Bonds				759,286		991,711	Notes Payable to Holdings

							5.80% Due 2012		500,000			500,000
Senior Notes:							3.83% Due 2010		350,000			350,000
							3.72% Due 2009		350,000			350,000

5 3/8%		2004		—		300,000	Total Notes Payable to Holdings		1,200,000			1,200,000

7 5/8%		2005		302,439		302,439
8 7/8%		2007		200,000		200,000	Other		—			195
7 3/4%		2008		600,000		600,000	Unamortized discount		(1,496	)		(2,018	)

Total Senior Notes			$	1,102,439	$	1,402,439	Total Long-Term Debt		3,473,989			4,006,087

							Less long-term debt due
							within one year		550,420			532,620

							Long-Term Debt due after
							one year	$	2,923,569		$	3,473,467



⁽¹⁾ Refinanced to auction rate mode on December 11, 2003. Effective interest rate at March 31, 2005 and March 31, 2004 was 2.70 percent and 1.18 percent, respectively.

⁽²⁾ Refinanced to auction rate mode on May 27, 2004. Effective interest rate at March 31, 2005 was 2.10 percent.

⁽³⁾ Refinanced to auction rate mode on May 1, 2003. Effective interest rate at March 31, 2005 and March 31, 2004 was 2.35 percent and 1.19 percent, respectively.

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:


($’s in millions)
Fiscal Year	Amount

2006	$	550
2007		275
2008		200
2009		600
2010		350
Thereafter		1,500

Total	$	3,475

The current portion of capital lease obligations is reflected in the other current liabilities line item on the Consolidated Balance Sheet and was approximately $1.0 million at March 31, 2005 and 2004. The non-current portion of capital lease obligations is reflected in the “Other” line item on the Consolidated Balance Sheet and was approximately $5 million at March 31, 2005 and 2004, respectively.

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

Early Extinguishment of Debt

During the years ended March 31, 2005, 2004 and 2003, the Company defeased or redeemed approximately $0, $658 million and $122 million, respectively, in long-term debt prior to its scheduled maturity.

Losses resulting from the early redemption of debt are recorded as a regulatory asset. They are deferred and amortized as interest expense ratably over the lives of the related issues in accordance with PSC directives as discussed in Note B – Rate and Regulatory Issues – Loss on Reacquired Debt.

NOTE F – SHORT-TERM DEBT

The Company had short-term debt outstanding of $401 million and $464 million at March 31, 2005, 2004, respectively, from the inter-company money pool. The Company has regulatory approval from the Securities and Exchange Commission (SEC), under the Public Utility Holding Company Act of 1935, to issue up to $1 billion of short-term debt. National Grid and certain subsidiaries, including the Company, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies that invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice. The average interest rate for the money pool was 1.80 percent, 1.11 percent and 1.62 percent for fiscal years 2005, 2004 and 2003, respectively.

The Company had no short-term debt outstanding to third-parties at March 31, 2005, 2004 or 2003.

NOTE G – FEDERAL AND STATE INCOME TAXES

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


	Year Ended March 31,
(In thousands of dollars)	2005			2004			2003

Components of federal and state income taxes:
Current tax expense (benefit):
Federal	$	(30,229	)	$	(12,003	)	$	(34,908	)
State		9,459			(474	)		14,320

		(20,770	)		(12,477	)		(20,588	)

Deferred tax expense (benefit):
Federal		177,180			128,426			111,157
State		3,542			20,022			(344	)

		180,722			148,448			110,813

Total	$	159,952		$	135,971		$	90,225


Total income taxes in the consolidated statements of operations:
Income taxes charged to operations	$	171,230		$	138,843		$	93,277
Income taxes credited to “Other income (deductions)”		(11,278	)		(2,872	)		(3,052	)

Total	$	159,952		$	135,971		$	90,225

Reconciliation between federal income taxes and the tax computed at prevailing U.S. statutory rate on income before income taxes:


	Year Ended March 31,
(In thousands of dollars)	2005			2004			2003

Computed tax	$	148,371		$	96,481		$	75,641

Increase (reduction) including those attributable to flow-through of certain tax adjustments:
Depreciation		16,982			21,397			12,183
Cost of removal		(5,664	)		(6,857	)		(6,730	)
Allowance for funds used during construction — (a)		(1	)		3			642
State income taxes		8,451			12,736			20,174
Non-deductible executive compensation		—			—			(9,878	)
Accrual to return adjustment		3,427			19,842			6,934

Debt premium and mortgage recording tax		487			(1,556	)		3,196
Real estate taxes		—			—			(9,300	)
E.S.O.P. dividends		(1,307	)		—			—
Dividends exclusion – federal income tax returns		(174	)		(149	)		—
Provided at other than statutory rate		(1	)		(2	)		(2	)
Voluntary Early Retirement Plan		—			—			(251	)
Medicare Act		(3,579	)		—			—
Subsidiaries		136			250			—
Deferred investment tax credit reversal		(2,866	)		(2,872	)		(3,029	)
Other		(4,310	)		(3,302	)		645

Total		11,581			39,490			14,584

Federal and State Income Taxes	$	159,952		$	135,971		$	90,225

(a)

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

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


At March 31 (In thousands of dollars)	2005			2004

Alternative minimum tax	$	111,609		$	81,639
Unbilled revenues		23,458			22,611
Non-utilized NOL carryforward		105,212			318,216
Liability for environmental costs		198,621			148,325
Voluntary early retirement program		47,558			219,237
Bad debts		29,474			29,474
Pension and other post-retirement benefits		185,324			40,830
Other		209,550			265,082

Total deferred tax assets		910,806			1,125,414


Depreciation related		(921,928	)		(921,798	)
Investment tax credit related		(40,677	)		(43,203	)
Deferred environmental restoration costs		(200,175	)		(148,325	)
Merger rate plan stranded costs		(848,182	)		(896,816	)
Merger fair value pension and OPEB adjustment		(128,188	)		(146,898	)
Bond redemption and debt discount		(25,056	)		(30,772	)
Pension and other post-retirement benefits		(88,830	)		(110,163	)
Other		(61,969	)		(105,527	)

Total deferred tax liabilities		(2,315,005	)		(2,403,502	)

Net accumulated deferred income tax liability	$	(1,404,199	)	$	(1,278,088	)
Current portion (net deferred tax asset)		307,431			273,135

Net accumulated deferred income tax liability (non-current)	$	(1,711,630	)	$	(1,551,223	)

The Company has been audited and reported on by the Internal Revenue Service (IRS) through December 31, 1998.

In December 1998, the Company received a ruling from the IRS which provided that the amount of cash and the value of common stock that was paid by the Company to the subject terminated IPP Parties was deductible in 1998 which resulted in the Company not paying any regular federal income taxes for 1998, and further generated a substantial net operating loss for federal income tax purposes. The Company carried back a portion of the unused net operating loss (NOL) to the years 1996 and 1997, and also for the years 1988 through 1990, which resulted in federal income tax refunds of $135 million that were received in January 1999. As a result of the merger with National Grid, the Company is now part of the consolidated tax return filing group of National Grid General Partnership (the parent company, through an intermediary entity, of National Grid). The Company anticipates that the consolidated tax filing group will be able to utilize the remaining NOL carryforward prior to its expiration in 2019. The amount of the NOL carryforward as of March 31, 2005 and 2004 was $301 million and $909 million, respectively. National Grid’s ability to utilize the NOL carryforward generated as a result of the MRA and the utilization of alternative minimum tax credits is affected by the rules of Section 382 of the Internal Revenue Code.

There were no valuation allowances for deferred tax assets at March 31, 2005 or 2004.

NOTE H — EMPLOYEE BENEFITS

Summary

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

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

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

Funding Policy

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

Investment Strategy

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

The target asset allocations for the benefit plans are:


	Pension Benefits						PBOPs
	2005			2004			2005			2004

U.S. Equities		44	%		42	%		50	%		50	%
Global Equities (including U.S.)		7	%		7	%		—			—
Non-U.S. Equities		11	%		11	%		15	%		15	%
Fixed Income		35	%		35	%		35	%		35	%
Private Equity and Property		3	%		5	%		—			—

		100	%		100	%		100	%		100	%

Expected Rate of 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.

Pension Benefits

The Company’s net periodic benefit cost for the years ended March 31, 2005, 2004 and 2003 included the following components:


	Year Ended March 31,
(In thousands)	2005			2004			2003

Service cost-benefits earned during the period	$	29,324		$	28,093		$	24,970
Plus (less):
Interest cost on projected benefit obligation		71,014			74,863			83,493
Return on plan assets at expected long-term rate		(67,787	)		(71,391	)		(75,613	)
Amortization of unrecognized prior service cost		1,851			1,160			—
Amortization of unrecognized loss		26,269			18,026			5,559

Net periodic benefit costs before settlement curtailments	$	60,671		$	50,751		$	38,409

Settlement and curtailment loss		185			21,798			29,548
Special termination benefits not included above		—			14,300			—

Net periodic benefit costs	$	60,856		$	86,849		$	67,957

The following weighted average assumptions were used to determine the net periodic pension cost. The expected long-term rate of return on plan assets will be decreased to 8.25% for the calculation of fiscal year 2006 pension expense.


	Year Ended March 31,
	2005			2004			2003

Discount rate		5.75	%		6.25	%		6.25	%
Rate of compensation increase		3.25	%		3.25	%		3.25	%
Expected return on plan assets		8.50	%		8.50	%		8.50	%

The following table provides a reconciliation of the plans’ fair value of assets for the fiscal years 2005 and 2004.


(In thousands)	2005			2004

Reconciliation of change in plan assets:
Fair value of plan assets at beginning of period	$	845,900		$	737,593
Actual return on plan assets during year		52,246			207,264
Company contributions		81,730			90,194
Benefits paid from plan assets		(148,350	)		(54,689	)
Settlements		(1,057	)		(134,462	)

Fair value of plan assets at end of period	$	830,469		$	845,900

The following table provides a reconciliation of the Company’s pension plans’ percentage distribution of the fair market value of the types of assets held in the pension plan’s trust for the fiscal years ended March 31, 2005 and 2004.


	2005			2004

Distribution of plan assets:
Debt securities		34	%		33	%
Equity securities		66	%		67	%

		100	%		100	%

The expected contribution to the Company’s pension plans during fiscal year 2006 is approximately $80 million.

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


(In thousands)	2005			2004

Accumulated benefit obligation	$	1,265,181		$	1,234,898

Change in benefit obligation:
Benefit obligation at beginning of period	$	1,298,548		$	1,296,660
Service cost		29,324			28,093
Interest cost		71,014			74,863
Actuarial loss		98,380			73,783
Plan amendments		31,201			—
Benefits paid		(148,350	)		(54,689	)
Settlements		(1,058	)		(134,462	)
Special termination benefits		—			14,300

Benefit obligation at end of period	$	1,379,059		$	1,298,548


(In thousands)	2005			2004

Funded status	$	(548,590	)	$	(452,648	)
Unrecognized actuarial loss		309,737			222,270
Unrecognized prior service cost		40,339			10,990

Net amount recognized on the balance sheet	$	(198,514	)	$	(219,388	)


(In thousands)	2005			2004

Amounts recognized on the balance sheet consist of:
Employee pension liability	$	(434,712	)	$	(389,003	)
Intangible asset		40,339			10,990


(In thousands)	2005			2004

Regulatory assets		194,302			157,068
Accumulated other comprehensive income		1,557			1,557

Net amount recognized on the balance sheet	$	(198,514	)	$	(219,388	)

The following weighted average assumptions were used to determine the pension benefit obligation at March 31, 2005 and 2004.


	2005			2004

Discount rate		5.75	%		5.75	%
Average rate of increase in future compensation level		3.90	%		3.25	%

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


(In thousands)	Pension Benefits

2006	$	110,000
2007	$	110,000
2008	$	109,000
2009	$	111,000
2010	$	117,000
2011-2015	$	666,000

Postretirement Benefit Plans Other than Pensions: The Company’s total cost of PBOPs for the years ended March 31, 2005, 2004 and 2003 included the following components:


	Year Ended March 31,
(In thousands)	2005			2004			2003

Service cost — benefits earned during the period	$	13,160		$	8,629		$	6,745
Plus (less):
Interest cost on projected benefit obligation		62,887			57,952			55,551
Return on plan assets at expected long-term rate		(45,798	)		(34,578	)		(23,642	)
Amortization of prior service cost		5,915			—			—
Amortization of net (gain) loss		24,310			22,996			(498	)

Net periodic benefit costs before settlement and curtailments	$	60,474		$	54,999		$	38,156
Special termination benefits not included above		—			641			—

Net periodic benefit costs	$	60,474		$	55,640		$	38,156

The following weighted average assumptions were used to determine the net periodic post-retirement benefits cost. The expected long-term rate of return on plan assets will be decreased to 8.17% for the calculation of fiscal year 2006 PBOP expense.


(In thousands)	2005			2004			2003

Discount rate		5.75	%		6.25	%		6.25	%


(In thousands)	2005			2004			2003

Expected return on plan assets		8.26	%		8.00	%		8.50	%
Medical trend
Initial		10.00	%		10.00	%		10.00	%
Ultimate		5.00	%		5.00	%		5.00	%
Year ultimate rate is reached		2009			2008			2007

The following table provides a reconciliation of the Company’s portion of the Companies’ PBOP fair value of assets for the fiscal years ended March 31, 2005 and 2004.


(In thousands)	2005			2004

Reconciliation of change in plan assets:
Fair value of plan assets at beginning of period	$	589,478		$	330,749
Actual return on plan assets during year		31,836			92,305
Company contributions		27,600			175,945
Benefits paid from plan assets		(58,997	)		(9,521	)

Fair value of plan assets at end of period	$	589,917		$	589,478

The following table provides the percentage distribution of the fair market value of the types of assets held in the PBOP trust at March 31.


	2005			2004

Distribution of plan assets:
Debt securities		32	%		35	%
Equity securities		67	%		63	%
Other		1	%		2	%

		100	%		100	%

The Company expects to contribute approximately $61 million to its PBOP plans in fiscal year 2006.

The following provides the reconciliation of the benefit obligation, funded status and the assumptions used in developing the obligations for the Company’s PBOP plan at March 31:


(In thousands)	2005			2004

Change in benefit obligation:
Benefit obligation at beginning of period	$	1,059,003		$	932,596
Service cost		13,160			8,629
Interest cost		62,887			57,952
Actuarial loss		39,897			111,361
Plan amendments		152,967			—
Benefits paid		(59,681	)		(52,176	)
Special termination benefits		—			641

Benefit obligation at end of period	$	1,268,233		$	1,059,003


(In thousands)	2005			2004

Funded status	$	(678,317	)	$	(469,525	)
Unrecognized prior service cost		147,052			—
Unrecognized actuarial loss		268,659			239,110

Net amount recognized	$	(262,606	)	$	(230,415	)


	2005			2004

Discount rate		5.75	%		5.75	%

Health care cost trend
Initial		10.00	%		10.00	%
Ultimate		5.00	%		5.00	%
Year ultimate rate reached		2010			2009

The following PBOP benefit payments and subsidies, which reflect expected future service, as appropriate, are expected to be paid:


(In thousands)	Payments		Subsidies

2006	$	60,000	$	—
2007		63,000		4,000
2008		65,000		5,000
2009		65,000		5,000
2010		64,000		5,000
2011-2015		308,000		29,000

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


(In thousands)	2005			2004

Increase 1%
Total of service cost plus interest cost	$	13,985		$	7,789
Post-retirement benefit obligation		196,034			107,991
Decrease 1%
Total of service cost plus interest cost		(11,629	)		(6,880	)
Post-retirement benefit obligation		(169,719	)		(97,642	)

PSC Audit

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 per cent (nominal) measured as of that date.

Additional Minimum Pension Liability

The Company has recorded an additional minimum pension liability of approximately $236 million and $170 million at March 31, 2005 and 2004, respectively, for its qualified pension plans because the pension plans’ accumulated benefit obligation was in excess of the prepaid pension asset and accrued pension liability on the balance sheet. While the offset to this entry would normally be a charge after-tax to other comprehensive income, due to the nature of its rate plan, the Company has instead recorded a pre-tax regulatory asset.

Voluntary Early Retirement Offer

In fiscal 2004, National Grid made a voluntary early retirement offer (VERO) to eligible non-union employees. The Company expensed approximately $19 million of VERO costs in the fiscal 2004. This amount included approximately $9 million allocated to the Company from National Grid USA Service Company, an affiliate.

Settlement Losses

As the result of the decline in the stock market since the close of the merger with Niagara Mohawk and a reduction in the discount rate applied to pension obligations, the Company has an unrecognized loss in its pension plans. Under SFAS No. 88 “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” (FAS 88), the Company must recognize a portion of this loss immediately when payouts from the plans exceed a certain amount. The Company recognized approximately $22 million in fiscal 2004 relating to the remeasurement of the benefit plans from the VERO. The Company had a net settlement loss of approximately $30 million in fiscal 2003 relating to normal lump-sum distributions and the spin-off of the assets and liabilities related to the sale of NM Energy.

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.

Regulatory treatment of pensions and PBOP plans

In addition to the regulatory assets established in connection with purchase accounting and the additional minimum pension liability discussed above, the regulatory asset account “Pension and postretirement benefit plans” includes certain other components. First, the Company is required under the Merger Rate Plan to defer the difference between pension and postretirement benefit expense and the allowance in rates for these costs. Also, the regulatory asset account includes the unamortized portion of the merger early retirement program costs, a postretirement benefit phase-in deferral established in the mid-1990’s, and the offset to the additional minimum pension liability discussed above. The merger early retirement program costs are being amortized unevenly over the 10 years of the Merger Rate Plan with larger amounts being amortized in the earlier years. This amortization in fiscal 2005 and 2004 was approximately $7 million and $8 million, respectively. The phase-in deferral is being amortized at a rate of approximately $3 million per year.

Defined contribution plan

The Company also has a defined contribution pension plan (employee savings fund plan) that covers substantially all employees. Employer matching contributions of approximately $7 million, $7 million, and $8 million were expensed for the fiscal years ended March 31, 2005, 2004 and 2003, respectively.

Medicare Act of 2003

The Medicare Prescription Drug, Improvement and Modernization Act was signed into law on December 8, 2003. It created a new Medicare prescription drug benefit (Medicare Part D) and a federal subsidy to sponsors of retiree healthcare plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. On May 19, 2004, the FASB issued Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the FSP). The FSP provides guidance on accounting for the effects of the Act, which resulted in a reduction in the APBO for the subsidy related to benefits attributed to past service. The reduction in the APBO represents a deferred actuarial gain in the amount of $71.5 million for the Company’s postretirement benefits plan as of July 1, 2004. On January 21, 2005 final regulations were issued on the new Medicare prescription drug program. The impact on plan obligations as a result of the final regulations was not significant.


($’s in 000’s)
Reduction in Net Periodic
Benefit Cost For the Year
Ended March 31,	2005

Service cost	$	491
Interest cost		3,713
Recognized actuarial loss		6,022

Total expense reduction	$	10,226
Annualized expense reduction	$	13,635

NOTE I – PREFERRED STOCK

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


									Redemption price
	Shares				($’s in 000’s)				per share
	March 31,		March 31,		March 31,		March 31,		(Before adding
Series	2005		2004		2005		2004		accumulated dividends)

Preferred $100 par value:
3.40%		57,536		57,536	$	5,754	$	5,754	$	103.50
3.60%		137,139		137,139		13,714		13,714		104.85
3.90%		94,967		94,967		9,496		9,496		106.00


									Redemption price
	Shares				($’s in 000’s)				per share
	March 31,		March 31,		March 31,		March 31,		(Before adding
Series	2005		2004		2005		2004		accumulated dividends)

4.10%		52,830		52,830		5,283		5,283		102.00
4.85%		35,128		35,128		3,513		3,513		102.00
5.25%		34,115		34,115		3,410		3,410		102.00
Preferred $25 par value:
Adjustable Rate - Series D		—		503,100		—		25,155		50.00	*

Total preferred stock		411,715		914,815	$	41,170	$	66,325

*	Redeemed on December 31, 2004.

During fiscal 2005, the Company redeemed all outstanding Cumulative Fixed/Adjustable Rate Series D Preferred Stock for $25 million.

NOTE J – SEGMENTS

The Company’s reportable segments are electricity-transmission, electricity-distribution, including the sub-segment stranded cost recoveries and gas-distribution. The Company is engaged principally in the business of the purchase, transmission, and distribution of electricity and the purchase, distribution, sale, and transportation of natural gas in New York State. Certain information regarding the Company’s segments is set forth in the following table. General corporate expenses, property common to the various segments, and depreciation of such common property have been allocated to the segments based on labor or plant, using a percentage derived from total labor or plant amounts charged directly to certain operating expense accounts or certain plant accounts. Corporate assets consist primarily of other property and investments, cash, restricted cash, current deferred income taxes, and unamortized debt expense.


					Electricity -		Total
	Electricity -		Electricity –		Stranded Cost		Electricity		Gas –
	Transmission		Distribution		Recoveries		Distribution		Distribution		Corporate		Total

Year ended March 31, 2005
Operating revenue	$	255	$	2,376	$	486	$	2,862	$	808	$	—	$	3,925
Operating income before income taxes		105		286		176		462		105		—		672
Depreciation and amortization		35		129		—		129		37		—		201
Amortization of stranded costs		—		—		251		251		—		—		251

Year ended March 31, 2004
Operating revenue	$	255	$	2,457	$	572	$	3,029	$	780	$	—	$	4,064
Operating income before income taxes		93		234		183		417		68		—		578
Depreciation and amortization		35		130		—		130		36		—		201
Amortization of stranded costs		—		—		194		194		—		—		194

Year ended March 31, 2003
Operating revenue	$	248	$	2,545	$	517	$	3,062	$	709	$	—	$	4,019
Operating income before income taxes		85		256		181		437		68		—		590
Depreciation and amortization		35		127		—		127		36		—		198
Amortization of stranded costs		—		—		149		149		—		—		149


						Electricity -		Total
	Electricity -		Electricity –			Stranded Cost		Electricity			Gas –
	Transmission		Distribution			Recoveries		Distribution			Distribution		Corporate		Total

Goodwill
Goodwill, at March 31, 2004	$	303	$	708		$	—	$	708		$	215	$	—	$	1,226
Change in goodwill		—		(2	)		—		(2	)		—		—		(2	)
Goodwill, at March 31, 2005	$	303	$	706		$	—	$	706		$	215	$	—	$	1,224

Total Assets
At March 31, 2005	$	1,557	$	5,193		$	3,402	$	8,595		$	1,819	$	547	$	12,518
At March 31, 2004	$	1,546	$	5,137		$	3,672	$	8,809		$	1,686	$	578	$	12,619

NOTE K – STOCK BASED COMPENSATION

Prior to the merger, stock appreciation rights (SARs), tied to the price of the Holdings’ share price were granted to officers, key employees and directors. The table below sets forth the activity under the SARs program for the periods March 31, 2003 through March 31, 2005.


								Options
								Wtd. Avg.
								Exercise
	SARs*			Units		Options		Price

Outstanding at March 31, 2003		752,880			—		—		—

Exercised		(411,612	)

Outstanding at March 31, 2004		341,268			—		—		—

Exercised		(93,146	)
Outstanding at March 31, 2005		248,122

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

Included in the Company’s results of operations for years ended March 31, 2005 and 2004, is approximately $1 million and $5 million, respectively, related to the SARs program.

Since SARs are payable in cash, the accounting under APB No. 25 and SFAS No. 123 is the same.

NOTE L – DERIVATIVES AND HEDGING ACTIVITIES

In the normal course of business, the Company is party to derivative financial instruments (derivatives) that are principally used to manage commodity prices associated with its natural gas and electric operations. These financial exposures are monitored and managed as an integral part of the Company’s overall financial risk-management policy. At the core of the policy is a condition that the Company will engage in activities at risk only to the extent that those activities fall within commodities and financial markets to which it has a physical market exposure in terms and volumes consistent with its core business. The Company does not issue or intend to hold derivative instruments for speculative trading purposes. Derivatives are accounted for in accordance with SFAS 133, which requires derivatives to be reported at fair value as assets or liabilities on the balance sheet. The change in fair value of instruments that qualify for hedge accounting are deferred in Accumulated Other Comprehensive Income and will be reclassified through purchased electricity or purchased gas expense within the next twelve months. Other instruments are deferred in regulatory assets or liabilities according to current rate agreements and are reclassified through purchased electricity or gas expense in the hedge months. The Company’s rate agreements allow for the pass-through of the commodity costs of electricity and natural gas, including the costs of the hedging programs.

The Company has eight indexed swap contracts, expiring in June 2008 that resulted from the MRA. These derivatives are not designated as hedging instruments and are covered by regulatory rulings that allow the gains and losses to be recorded as regulatory assets or regulatory liabilities. As of March 31, 2005 and 2004, the Company had recorded liabilities at net present value of $619 million and $715 million, respectively, for these swap contracts and had recorded a corresponding swap contracts regulatory asset. The asset and liability are amortized over the remaining term of the swaps as nominal energy quantities are settled and are adjusted as periodic reassessments are made of energy price forecasts.

At March 31, 2005, the Company projects that it will make the following payments in connection with its swap contracts for the fiscal years 2006 through 2008, subject to changes in market prices and indexing provisions:


	Projected
	Payment
Year Ended	(in thousands
March 31,	of dollars)

2006	$	203,558
2007		196,324
2008		182,834
2009		36,236

Total	$	618,952

The Company uses New York Mercantile Exchange (NYMEX) gas futures to hedge the gas commodity component of its indexed swap contracts. These instruments, as used, do not qualify for hedge accounting status under SFAS 133. Cash flow hedges that qualify under SFAS 133 are as follows: NYMEX gas futures for the purchases of natural gas and NYMEX electric swap contracts hedging the purchases of electricity.

The following table represents the open positions at March 31, 2005 and the results on operations of these instruments for the year ended March 31, 2005.


($’s in 000’s)	Balances as of March 31, 2005
												Year Ended
									Accumulated			March 31, 2005
						Accumulated			Deferred			Gain/(Loss)
			Regulatory			OCI ,**			Income Tax			Reclass to
Derivative Instrument	Asset*		Deferral			net of tax			on OCI**			Commodity Costs

*Qualified for Hedge Accounting*

NYMEX futures — gas supply	$	7,233.4	$	—		$	(11,861.7	)	$	(7,907.8	)	$	7,950.1

NYMEX electric swaps — electric supply	$	1,067.4	$	—		$	(950.3	)	$	(633.5	)	$	43.3

*Non-Qualified for Hedge Accounting*

NYMEX futures — IPP swaps/non-MRA IPP	$	27,019.7	$	(29,865.8	)	$	—		$	—		$	19,376.6

*		Differences between asset and regulatory or other comprehensive income deferral represent contracts settled for the following month.

**		Other Comprehensive Income (OCI)

At March 31, 2004, the Company recorded a deferred gain on the futures contracts hedging the IPP swaps and non-MRA IPP of $21.5 million, offset by the consolidated balance sheet item “Derivative Instruments” for $20.3 million, with the resulting $2.1 million having settled through cash for the hedge month of April 2004. For the twelve months ended March 31, 2004, settlement of NYMEX futures contracts resulted in a decrease to purchased power expense of $17.3 million.

The gains and losses on the derivatives that are deferred and reported in accumulated other comprehensive income will be reclassified as purchased energy expense in the periods in which expense is impacted by the variability of the cash flows of the hedged item. For the twelve months ended March 31, 2005, the realized net gain of $8 million from hedging instruments, as shown in the table above, was recorded to gas purchases offset by a corresponding increase in the cost of a comparable amount of gas. For the twelve months ended March 31, 2004, a net loss of $4.2 million was recorded to gas purchases offset by a corresponding decrease in the cost of a comparable amount of gas.

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

At March 31, 2005, the Company recorded a deferred gain on NYMEX electric swap contracts to hedge electricity purchases of $1.1 million. There were no open electric swaps at March 31, 2004.

NOTE M – RESTRICTION ON COMMON DIVIDENDS

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

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

NOTE N – ADDITIONAL PAID-IN CAPITAL

The following table details the changes in the equity account, “Additional paid-in capital”


($ in 000's)

March 31, 2003	$	2,621,440
Equity contribution from Holdings		309,000
Net loss on preferred stock tender offers		(939	)

March 31, 2004	$	2,929,501

March 31, 2005	$	2,929,501

The contribution from Holding in fiscal 2004 was for the funding of the pension and post-retirement benefit trusts associated with a PSC settlement See Note H – Employee Benefits.

NOTE O – COST OF REMOVAL

In 2001, FASB issued FAS 143. FAS 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. The Company was required to adopt FAS 143 as of April 1, 2003. Retirement obligations associated with long-lived assets included within the scope of FAS 143 are those for which there is a legal obligation under existing or enacted law, statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.

The Company does not have any material asset retirement obligations arising from legal obligations as defined under FAS 143. However, under the Company’s current and prior rate plans it has collected through rates an implied cost of removal for its plant assets. This cost of removal collected from customers differs from the FAS 143 definition of an asset retirement obligation in that these collections are for costs to remove an asset when it is no longer deemed usable (i.e. broken or obsolete) and not necessarily from a legal obligation. For a vast majority

of its electric and gas transmission and distribution assets the Company would use these funds to remove the asset so a new one could be installed in its place.

The cost of removal collections from customers has historically been embedded within accumulated depreciation (as these costs have been charged over time through depreciation expense). With the adoption of FAS 143 the Company has reclassified these cost of removal collections to a regulatory liability account to more properly reflect the future usage of these collections. The Company estimates it has collected over time approximately $318 million and $314 million for cost of removal through March 31, 2005 and March 31, 2004, respectively.

In March 2005, the FASB issued FIN 47 that clarifies that the term ‘conditional asset retirement obligation’ used in SFAS No. 143, ‘Accounting for Asset Retirement Obligation’ (SFAS 143) refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future even that may or may not be within the control of the Group. 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.

NOTE P – QUARTERLY FINANCIAL DATA (UNAUDITED)

Operating revenues, operating income, and net income (loss) by quarter from April 1, 2003 through March 31, 2005 are shown in the following table. The Company believes it has included all adjustments necessary for a fair presentation of the results of operations for the quarters. Due to the seasonal nature of the regulated utility business, the annual amounts are not generated evenly by quarter during the year. The Company’s quarterly results of operations reflect the seasonal nature of its business, with peak electric loads in summer and winter periods. Gas sales peak in the winter.


	In thousands of dollars
			Operating		Operating		Net
Quarter Ended			Revenues		Income		Income

March 31,		2005	$	1,215,027	$	164,521	$	116,679
		2004		1,223,922		131,882		62,123
December 31,		2004		907,037		116,611		55,517
		2003		959,671		101,860		31,658
September 30,		2004		912,868		114,948		50,218
		2003		930,647		112,228		41,776
June 30,		2004		890,239		104,614		40,835
		2003		949,377		93,625		4,133

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

The Company has nothing to report for this item.

ITEM 9A. CONTROLS AND PROCEDURES

The Company has carried out an evaluation under the supervision and with the participation of its management, including the Chief Financial Officer and President, of the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives. Based on and as of that evaluation, it was determined that these disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in reports that the Company files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required.

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

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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



Name	Age		Position
William F. Edwards		48	President and Director
John G. Cochrane		47	Chief Financial Officer
Joseph T. Ash, Jr.		56	Vice President, Energy Supply, Pricing and Regulatory Proceedings
Edward A. Capomacchio		59	Controller
Michael E. Jesanis		48	President and Chief Executive Officer of National Grid USA and Director
Michael J. Kelleher		47	Senior Vice President, Business Services
Clement E. Nadeau		53	Senior Vice President, Operations, and Director
Kwong O. Nuey, Jr.		57	Director
Anthony C. Pini		52	Senior Vice President, Customer Service, and Director
Lawrence J. Reilly		49	Senior Vice President and General Counsel of National Grid USA
Jeffrey A. Scott		50	Senior Vice President, Transmission, of National Grid USA
Steven W. Tasker		47	Senior Vice President and Treasurer

Directors are elected at the annual meeting of stockholders and hold office until the next annual meeting or a special meeting in lieu thereof, and until their successors are elected and qualified. All of the directors were elected in 2004. There are no family relationships between any of the directors and executive officers listed in the table. There are no arrangements or understandings

between any executive officer and any other person pursuant to which he was selected as an officer.

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

Mr. Cochrane was elected Chief Financial Officer effective August 1, 2002. He has served as National Grid USA’s Chief Financial Officer since January 2001, Senior Vice President since May 2002 and Treasurer since April 2003 and has served as Treasurer of National Grid USA Service Company since May 2003. From 1998 to 2002, he was Treasurer of National Grid USA (and its predecessor, New England Electric System) and of National Grid USA Service Company.

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

Mr. Capomacchio was appointed Controller of the Company and Vice President and Controller of National Grid USA Service Company in January 2002. He has served as Controller of the Company’s New England retail affiliates Massachusetts Electric Company, The Narragansett Electric Company, Nantucket Electric Company and Granite State Electric Company since May 2001. Mr. Capomacchio was Assistant Controller of the Service Company from 1998 to 2002.

Mr. Jesanis was appointed director of the Company in January 2002. He became President of National Grid USA in November 2003 having been its Chief Operating Officer and responsible for the day-to-day operations since January 2001. He served as Senior Vice President and Chief Financial Officer of National Grid USA’s predecessor, New England Electric System, from 1998 to 2000. Mr. Jesanis is also a director of National Grid USA and was appointed a director of National Grid Transco in July 2004.

Mr. Kelleher was elected Senior Vice President of the Company effective May 1, 2004. He served as Vice President of National Grid USA from January 2002 to March 2004 and as its Treasurer from April 2002 to April 2003. Prior to that, he served as Vice President Financial Planning of Niagara Mohawk Power Corporation from 1999 to 2001. He also served as Vice President Financial Planning of Niagara Mohawk Holdings, Inc. in 2000.

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

Mr. Nuey was elected Vice President and Chief Information Officer of National Grid USA Service Company effective January 31, 2002. He was the Vice President and Controller of National Grid USA Service Company from 2000 to 2002 and the Vice President and Director of Retail Information Services of the Company from 1997 to 2000.

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

Mr. Reilly has been Secretary and General Counsel of National Grid USA since January 2001. Since 2000 he has been National Grid USA Senior Vice President, and he served as President of Massachusetts Electric Company, The Narragansett Electric Company, Nantucket Electric Company and Granite State Electric Company from 1996 to 2000.

Mr. Scott has been a Senior Vice President and director of National Grid USA since August 1, 2003. He joined The National Grid Company in 1990, becoming Commercial Director of UK Transmission in February 2003. Currently, he is responsible for all operations associated with National Grid Transco’s US Transmission business.

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

Section 16(a) Beneficial Ownership Reporting Compliance

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

Senior Financial Officer Code of Ethics

The Company has adopted a code of ethics that applies to its principal executive officer, principal financial officer and principal accounting officer. This code is available on the National Grid Transco plc website, at www.ngtgroup.com, where any amendments or waivers will also be posted. There were no amendments to, or waivers under, our Code of Ethics in the fiscal year ended March 31, 2005.

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

ITEM 11. EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth the compensation paid or accrued for services rendered to Niagara Mohawk in the fiscal years ended March 31, 2005, 2004 and 2003 by the president and the four most highly paid persons who were serving as executive officers on March 31, 2005 (the Named Executive Officers).



			Annual Compensation (a)						Long-Term		All Other
									Compensation		Compen-
									Awards		sation ($)(d)
							Other Annual
Name and Principal							Compen-		Securities Underlying
Position	Year		Salary($)		Bonus($)(b)		sation ($)(c)		Options/ SARs(#)
William F. Edwards President		2005 2004 2003		420,000 399,994 399,993		266,410 210,000 224,396		3,675 7,000 6,010		0 0 56,206		540 270 1,823
Michael E. Jesanis (e) President & CEO, National Grid USA		2005 2004 2003		259,534 225,015 150,528		203,511 146,390 99,802		3,686 6,773 12,660		0 0 21,152		2,728 2,682 232
Michael J. Kelleher Senior Vice President Business Services and Economic Development		2005		203,333		108,352		130,640		0		9,540
Clement E. Nadeau Senior Vice President Operations		2005 2004 2003		218,750 210,000 209,997		151,091 120,250 149,098		6,150 11,096 8,882		0 0 29,508		828 5,889 807
Anthony C. Pini Senior Vice President Customer Service		2005 2004 2003		230,417 225,000 225,000		496,021 123,150 137,925		74,363 90,560 113,562		0 0 31,616		536 487 642



	(a)			Includes deferred compensation in category and year earned.
	(b)			The bonus figure represents cash bonuses and the fair market value of unrestricted securities of National Grid Transco awarded under an incentive compensation plan and cash bonuses awarded under the all-employees goals program. For Mr. Pini, it also includes a special cash bonus associated with the completion of certain corporate objectives.
	(c)			Includes amounts reimbursed for the payment of taxes on certain non-cash benefits and contributions to the incentive thrift plan that are not bonus contributions, including related deferred compensation plan match. For Mr. Pini, includes amounts reimbursed for housing expenses. For Mr. Kelleher, includes amounts reimbursed for relocation expenses.
	(d)			Includes Company contributions to life insurance. Also includes the value of financial services provided to Messrs. Jesanis and Kelleher.
	(e)			Mr. Jesanis performs service for affiliate companies. Compensation that is allocable to Niagara Mohawk is set forth in the table.

Long-Term Incentive Plans – Awards in Last Fiscal Year

The following table sets forth awards made under the National Grid Transco Performance Share Plan to the Named Executive Officers during fiscal 2005.



				Estimated Future Payouts
	Number of			Threshold		Maximum
Name	Shares (#)		Performance Period	(#)		(#)
William F. Edwards		5,329	July 1, 2004 through June 30, 2007		1,599		5,329
Michael E. Jesanis		19,987	July 1, 2004 through June 30, 2007		5,996		19,987
Michael J. Kelleher		2,538	July 1, 2004 through June 30, 2007		761		2,538
Clement E. Nadeau		3,197	July 1, 2004 through June 30, 2007		959		3,197
Anthony C. Pini		3,426	July 1, 2004 through June 30, 2007		1,028		3,426

Under the National Grid Transco Performance Share Plan, executives receive notional allocations of American Depositary Shares of National Grid Transco. Shares vest after three years, subject to the satisfaction of the relevant performance criterion, which is set at the date of grant. Shares must then be held for a further year, after which they are released. For the grants set forth above, the relevant criterion is total shareholder return (TSR) performance over a three-year period, relative to the TSR performances of a group of comparator companies. This comparator group includes companies in the energy sector, against which National Grid Transco benchmarks its performance for business purposes, and other utilities from the UK, Europe and USA. The proportion of the original award of shares that will transfer to participants will depend on National Grid Transco’s performance when compared to the comparator group. National Grid Transco must achieve median ranking in order for participants to realize the threshold payout of 30% of the original award. It must rank in the upper quartile relative to the comparator group for participants to achieve the maximum payout of 100% of the original award.

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

The following table sets forth, for the Named Executive Officers, the number of shares for which stock options were exercised in fiscal year 2005, the realized value or spread (the difference between the exercise price and market value on the date of exercise) and the number and unrealized spread of the unexercised options held by each at fiscal year-end.



			Number of Securities
			Underlying Unexercised
			Options on March 31, 2005		Value of Unexercised Options
	Options	Value	(#)		on March 31, 2005 ($)(a)(b)
Name	Exercised	Realized				Unexercisable
	(#)	($)	Exercisable	Unexercisable	Exercisable	(b)
William F. Edwards	0	0	0	56,206	0	9,566
Michael E. Jesanis	0	0	129,030	66,099	0	11,250
Michael J. Kelleher	0	0	0	33,724	0	5,740
Clement E. Nadeau	0	0	0	29,508	0	5,022
Anthony C. Pini	0	0	59,492	31,616	0	5,381



	(a)			Calculated based on the closing price on March 31, 2005 of National Grid Transco, plc Ordinary Shares traded on the London Stock Exchange (£4.9025). At March 31, 2005, the price per Ordinary Share was



				lower than the exercise price for certain stock option grants made to the Named Executive Officers.
	(b)			A conversion rate of $1.84/£1.00 was used to translate the option value, which is the exchange rate for the National Grid companies’ balance sheet at March 31, 2005.

The following table sets forth, for the Named Executive Officers, exercises of SARs in fiscal year 2005, the realized value or spread (the difference between the exercise price and market value on the date of exercise) and the number and unrealized spread of the unexercised options and SARs held by each at fiscal year-end.



					Number of Securities
					Underlying Unexercised
					SARs At Fiscal				Value of Unexercised SARs
	SARs		Value		Year-End (#)				At Fiscal Year-End ($)(a)
Name	Exercised		Realized
	(#)		($)		Exercisable		Unexercisable		Exercisable		Unexercisable
William F. Edwards		0		0		0		0		0		0
Michael Jesanis		0		0		0		0		0		0
Michael J. Kelleher		0		0		0		0		0		0
Clement E. Nadeau		0		0		12,312		0	$	265,974		0
Anthony C. Pini		0		0		0		0		0		0



	(a)			Calculated based on the closing price on March 31, 2005 of National Grid Transco American Depositary Shares traded on the New York Stock Exchange ($46.75). SAR grants were made under Niagara Mohawk’s Long Term Incentive Plan which was terminated when its parent, Niagara Mohawk Holdings, Inc. merged with a subsidiary of National Grid USA. At that time, outstanding grants of SARs were converted to SARs over National Grid Group American Depositary Shares using a specified exchange ratio.

Pension Plans

Executive Supplement Retirement Benefit Table



Five-Year
Average	Annual Annuity Value Based On Years of Service
Compensation		15 Years		20 Years		25 Years		30 Years		35 Years
$150,000		$	43,134	$	56,512	$	69,515	$	82,518	$	90,646
$200,000		$	59,134	$	77,512	$	95,390	$	113,268	$	124,646
$250,000		$	75,134	$	98,512	$	121,265	$	144,018	$	158,646
$300,000		$	91,134	$	119,512	$	147,140	$	174,768	$	192,646
$350,000		$	107,134	$	140,512	$	173,015	$	205,518	$	226,646
$400,000		$	123,134	$	161,512	$	198,890	$	236,268	$	260,646
$450,000		$	139,134	$	182,512	$	224,765	$	267,018	$	294,646
$500,000		$	155,134	$	203,512	$	250,640	$	297,768	$	328,646
$550,000		$	160,384	$	210,512	$	259,390	$	308,268	$	340,896
$600,000		$	165,634	$	217,512	$	268,140	$	318,768	$	353,146
$650,000		$	170,884	$	224,512	$	276,890	$	329,268	$	365,396
$700,000		$	176,134	$	231,512	$	285,640	$	339,768	$	377,646
$750,000		$	181,384	$	238,512	$	294,390	$	350,268	$	389,896
$800,000		$	186,634	$	245,512	$	303,140	$	360,768	$	402,146
$850,000		$	191,884	$	252,512	$	311,890	$	371,268	$	414,396



Five-Year
Average	Annual Annuity Value Based On Years of Service
Compensation		15 Years		20 Years		25 Years		30 Years		35 Years
$900,000		$	197,134	$	259,512	$	320,640	$	381,768	$	426,646
$1,000,000		$	207,634	$	273,512	$	338,140	$	402,768	$	451,146
$1,100,000		$	218,134	$	287,512	$	355,640	$	423,768	$	475,646
$1,200,000		$	228,634	$	301,512	$	373,140	$	444,768	$	500,146
$1,300,000		$	239,134	$	315,512	$	390,640	$	465,768	$	524,646
$1,400,000		$	249,634	$	329,512	$	408,140	$	486,768	$	549,146
$1,500,000		$	260,134	$	343,512	$	425,640	$	507,768	$	573,646

The table above shows the maximum retirement benefit an executive officer can earn in aggregate under the applicable tax-qualified plan (described below) together with the ESRP. In developing the ESRP benefit, final compensation includes both base salary and annual incentive pay. There is an offset contained within the ESRP formula for social security benefits.The benefit calculations are made as of March 31, 2005 and assume the officer has selected a straight life annuity commencing at age 65. Annual compensation limits of $210,000 under a tax-qualified plan will reduce the portion payable under the qualified pension plan for some highly compensated officers. The benefits listed are shown without any joint and survivor benefits. If a participant elected a 100 percent joint and survivor benefit at age 65, with a spouse of the same age, the benefit shown in the table would be reduced by approximately 16 percent.

For purposes of the pension program, the Named Executive Officers had approximately the following credited years of benefit service at March 31, 2005: William F. Edwards, 26 years; Michael E. Jesanis, 21 years; Michael J. Kelleher, 15 years; Clement E. Nadeau, 32 years; and Anthony C. Pini, 26 years.

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

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

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

Under the Nimo Plan, a participant’s retirement benefit is based on one of two formulas depending on age and years of service on July 1, 1998: the cash balance formula, or the highest five-year average compensation. Under the cash balance formula a participant’s retirement benefit grows monthly, according to pay credits (from 4 percent to 8 percent times base salary) plus interest credits. A non-union (management) employee who was at least 45 years of age and had 10 years of service on July 1, 1998 will receive the retirement benefit resulting from the higher of the two formulas.

Nonqualified Pension Plan: Executive Supplemental Retirement Plan

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

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

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

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

William F. Edwards Agreements. Mr. Edwards has an agreement providing for a lump sum bonus payment equal to one year’s base pay on the fourth anniversary of the merger, to the extent that certain performance objectives have been met. If Mr. Edwards is terminated other than for cause prior to the fourth anniversary, this bonus is payable on a prorated basis for his months of service beyond the merger date. In the event he is terminated without cause, Mr. Edwards is also entitled to receive a severance payment under the Executive Severance Plan (since it is higher than the formula provided in his agreement). The agreement provides for life insurance coverage equal to three times his base pay for his lifetime, and health care benefits for him and his dependents for their lifetimes.

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

Michael E. Jesanis Agreement. Mr. Jesanis has an agreement setting forth his salary and certain benefits, and providing for 12 months’ written notice for termination other than for cause or disability. There are no termination or change-in-control arrangements particular to Mr. Jesanis.

Post-retirement health and life insurance. At retirement, the Named Executive Officers may become eligible for post-retirement health and life insurance benefits determined based on their age and years of service. The executive may be required to contribute to the cost of benefits, depending on date of hire and total years of service. Provisions in the Retirees Health and Life Insurance Plan prevent changes in benefits adverse to the participants for three years following a change in control.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table indicates the number of ordinary shares of National Grid Transco beneficially owned as of June 1, 2005 by: (a) each of the Named Executive Officers; (b) each director of the Company; and (c) all directors and executive officers of the Company as a group. Except as indicated, each such person has sole investment and voting power with respect to the shares shown as being beneficially owned by such person, based on information provided to the Company. Each person listed in this table owns less than one percent of the outstanding equity securities of National Grid Transco. Niagara Mohawk Holdings, Inc. owns all of the common stock of the Company.



Name	Number of Shares
	Beneficially Owned*
William F. Edwards		86,621
Michael E. Jesanis		147,515
Michael J. Kelleher		33,724
Clement E. Nadeau		47,258
Anthony C. Pini		71,657
Kwong O. Nuey, Jr.		67,071
All directors and executive officers as a group (12 persons) (a)		906,581



	*			This number is expressed in terms of ordinary shares. It includes American Depositary Receipts listed on the New York Stock Exchange, each of which represents five ordinary shares.
	(a)			Includes shares held by Mr. Reilly’s spouse.

None.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

PricewaterhouseCoopers LLP, an independent registered public accounting firm, served as auditors of the Company for the fiscal year ended March 31, 2005.

Audit Fees

The aggregate fees billed by PricewaterhouseCoopers LLP for the audit of the Company’s financial statements and regulatory filings for the fiscal year ended March 31, 2005, and the reviews of quarterly reports on Form 10-Q filed during the fiscal year ended March 31, 2005 were $749,900. Fees billed by PricewaterhouseCoopers LLP for the audit of the Company’s financial statements and regulatory filings for the fiscal year ended March 31, 2004, and the reviews of quarterly reports on Form 10-Q filed during the fiscal year ended March 31, 2004 were $1,481,687.

Audit-related fees

There were no fees billed by PricewaterhouseCoopers LLP for assurance and related services that were reasonably related to the performance of the audit or review of the Company’s financial statements and are not disclosed under “Audit Fees” above in fiscal 2005.

Tax Fees

Aggregate fees billed by PricewaterhouseCoopers LLP to the Company for tax compliance, tax advice and tax planning were $1,600 and $77,983 in fiscal years 2005 and 2004, respectively.

All Other Fees

The Company did not pay any other type of fee and did not receive any other services from PricewaterhouseCoopers LLP during the fiscal years ended March 31, 2005 and March 31, 2004.

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

During the fiscal year ended March 31, 2005, all of the above-described services provided by PricewaterhouseCoopers LLP were pre-approved by the Audit Committee.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Financial Statements

	•		Report of Independent Registered Public Accounting Firm

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

Exhibits

The exhibit index is incorporated herein by reference.

Financial Statement Schedule

Schedule II – Valuation and Qualifying Accounts and Reserves

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

(In thousands of dollars)

Column A

Column B

Column C

Column D

Column E

Additions

Balance at

Charged to

Balance

Beginning

Costs and

Deductions

at End

Description

of Period

Expenses

(a)

of Period

Allowance for Doubtful
Accounts -Deducted from
Accounts Receivable in
the Consolidated
Balance Sheets

Year ended March 31, 2005

124,231

44,779

42,926

126,084

Year ended March 31, 2004

100,223

64,102

40,094

124,231

Year ended March 31, 2003

61,301

92,841

53,919

100,223

(a)

Uncollectible accounts written off net of recoveries.

(In thousands of dollars)

Column A

Column B

Column C

Column D

Column E

Additions

Balance at

Charged to

Balance

Beginning

Costs and

at End

Description

of Period

Expenses

Deductions

of Period

Miscellaneous
Valuation Reserves

Year Ended March 31, 2005

9,435

$—

9,435

—

Year Ended March 31, 2004

9,435

—

9,435

Year Ended March 31, 2003

9,435

—

9,435

SIGNATURES

Pursuant to the Requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company.


		NIAGARA MOHAWK POWER CORPORATION

Date: June 29, 2005	By:	/s/ William F. Edwards

		William F. Edwards
		President

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, this report has been signed below on June 29, 2005 by the following persons on behalf of the registrant and in the capacities indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company.


Signature		Title
/s/ William F. Edwards William F. Edwards		President and Director (Principal Executive Officer)

/s/ John G. Cochrane John G. Cochrane		Chief Financial Officer (Principal Financial Officer)

/s/ Edward A. Capomacchio Edward A. Capomacchio		Controller (Principal Accounting Officer)

/s/ Michael E. Jesanis Michael E. Jesanis		Director

/s/ Clement E. Nadeau Clement E. Nadeau		Director

/s/ Kwong O. Nuey Kwong O. Nuey		Director

/s/ Anthony C. Pini Anthony C. Pini		Director

NIAGARA MOHAWK POWER CORPORATION

EXHIBIT INDEX

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


Reference		Name
A		Niagara Mohawk Registration Statement No. 2-8214

B		Niagara Mohawk Registration Statement No. 2-8634

C		Central New York Power and Light Corporation Registration Statement No. 2-3414

D		Central New York Power and Light Corporation Registration Statement No. 2-5490

E		Niagara Mohawk Registration Statement No. 2-10501

F		Niagara Mohawk Registration Statement No. 2-12443

G		Niagara Mohawk Registration Statement No. 2-16193

H		Niagara Mohawk Registration Statement No. 2-26918

I		Niagara Mohawk Registration Statement No. 2-59500

J		Niagara Mohawk Registration Statement No. 2-70860

K		Niagara Mohawk Registration Statement No. 33-38093

L		Niagara Mohawk Registration Statement No. 33-47241

M		Niagara Mohawk Registration Statement No. 33-59594

N		Niagara Mohawk Registration Statement No. 33-49541

O		Niagara Mohawk Annual Report on Form 10-K for year ended December 31, 1994

P		Niagara Mohawk Annual Report on Form 10-K for year ended December 31, 1997

Q		Niagara Mohawk Annual Report on Form 10-K for year ended December 31, 1999


Reference		Name
R		Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended March 31, 1993

S		Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended September 30, 1993

T		Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended June 30, 1995

U		Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended March 31, 1998

V		Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended June 30, 1998

W		Niagara Mohawk Quarterly Report of Form 10-Q for quarter ended March 31, 1999

X		Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended September 30, 2001

Y		Niagara Mohawk Current Report on Form 8-K dated July 9, 1997

Z		Niagara Mohawk Current Report on Form 8-K dated October 10, 1997

AA		Niagara Mohawk Current Report on Form 8-K dated November 30, 1999

BB		Niagara Mohawk Current Report on Form 8-K dated May 9, 2000

CC		Niagara Mohawk Current Report on Form 8-K dated September 25, 2001

DD		Niagara Mohawk Annual Report on Form 10-K for the fiscal year ended March 31, 2003

EE		Niagara Mohawk Annual Report on Form 10-K for the fiscal year ended March 31, 2004

FF		New England Electric System Annual Report on Form 10-K for the fiscal year ended December 31, 1997

GG		New England Electric System Annual Report on Form 10-K for the fiscal year ended December 31, 1998


Reference		Name
HH		New England Power Company Annual Report on Form 10-K for the fiscal year ended March 31, 2002

II		National Grid Group Registration Statement on Form S-8 filed July 26, 2001

JJ		National Grid Group Annual Report on Form 20-F for the fiscal year ended March 31, 2002

KK		National Grid Transco Annual Report on Form 20-F for the fiscal year ended March 31, 2004

LL		National Grid Transco Annual Report on Form 20-F for the fiscal year ended March 31, 2005

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


	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
3(a)(1)	O	3(a)(1)	Certificate of Consolidation of New York Power and Light Corporation, Buffalo Niagara Electric Corporation and Central New York Power Corporation, filed in the office of the New York Secretary of State, January 5, 1950

3(a)(2)	O	3(a)(2)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk, filed in the office of the New York Secretary of State, January 5, 1950

3(a)(3)	O	3(a)(3)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk pursuant to Section 36 of the Stock Corporation Law of New York, filed August 22, 1952, in the office of the New York Secretary of State

3(a)(4)	O	3(a)(4)	Certificate of Niagara Mohawk pursuant to Section 11 of the Stock Corporation Law of New York filed May 5, 1954 in the office of the New York Secretary of State

3(a)(5)	O	3(a)(5)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk pursuant to Section 36 of the Stock Corporation Law of New York, filed January 9, 1957 in the office of the New York Secretary of State

3(a)(6)	O	3(a)(6)	Certificate of Niagara Mohawk pursuant to Section 11 of the Stock Corporation Law of New York, filed May 22, 1957 in the office of the New York Secretary of State

3(a)(7)	O	3(a)(7)	Certificate of Niagara Mohawk pursuant to Section 11 of the Stock Corporation Law of New York, filed February 18, 1958 in the office of the New York Secretary of State

3(a)(8)	O	3(a)(8)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 5, 1965 in the office of the New York Secretary of State

3(a)(9)	O	3(a)(9)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 24, 1967 in the office of the New York Secretary of State


	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
3(a)(10)	O	3(a)(10)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 19, 1968 in the office of the New York Secretary of State

3(a)(11)	O	3(a)(11)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed September 22, 1969 in the office of the New York Secretary of State

3(a)(12)	O	3(a)(12)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 12, 1971 in the office of the New York Secretary of State

3(a)(13)	O	3(a)(13)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 18, 1972 in the office of the New York Secretary of State

3(a)(14)	O	3(a)(14)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed June 26, 1973 in the office of the New York Secretary of State

3(a)(15)	O	3(a)(15)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 9, 1974 in the office of the New York Secretary of State

3(a)(16)	O	3(a)(16)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed March 12, 1975 in the office of the New York Secretary of State

3(a)(17)	O	3(a)(17)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 7, 1975 in the office of the New York Secretary of State


	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
3(a)(18)	O	3(a)(18)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 27, 1975 in the office of the New York Secretary of State

3(a)(19)	O	3(a)(19)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 7, 1976 in the office of the New York Secretary of State

3(a)(20)	O	3(a)(20)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed September 28, 1976 in the office of the New York Secretary of State

3(a)(21)	O	3(a)(21)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed January 27, 1978 in the office of the New York Secretary of State

3(a)(22)	O	3(a)(22)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 8, 1978 in the office of the New York Secretary of State

3(a)(23)	O	3(a)(23)	Certificate of Correction of the Certificate of Amendment filed May 7, 1976 of the Certificate of Incorporation under Section 105 of the Business Corporation Law of New York, filed July 13, 1978 in the office of the New York Secretary of State

3(a)(24)	O	3(a)(24)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed July 17, 1978 in the office of the New York Secretary of State

3(a)(25)	O	3(a)(25)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed March 3, 1980 in the office of the New York Secretary of State


	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
3(a)(26)	O	3(a)(26)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed March 31, 1981 in the office of the New York Secretary of State

3(a)(27)	O	3(a)(27)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed March 31, 1981 in the office of the New York Secretary of State

3(a)(28)	O	3(a)(28)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed April 22, 1981 in the office of the New York Secretary of State

3(a)(29)	O	3(a)(29)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 8, 1981 in the office of the New York Secretary of State

3(a)(30)	O	3(a)(30)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed April 26, 1982 in the office of the New York Secretary of State

3(a)(31)	O	3(a)(31)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed January 24, 1983 in the office of the New York Secretary of State

3(a)(32)	O	3(a)(32)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 3, 1983 in the office of the New York Secretary of State

3(a)(33)	O	3(a)(33)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed December 27, 1983 in the office of the New York Secretary of State


	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
3(a)(34)	O	3(a)(34)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed December 27, 1983 in the office of the New York Secretary of State

3(a)(35)	O	3(a)(35)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed June 4, 1984 in the office of the New York Secretary of State

3(a)(36)	O	3(a)(36)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 29, 1984 in the office of the New York Secretary of State

3(a)(37)	O	3(a)(37)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed April 17, 1985 in the office of the New York Secretary of State

3(a)(38)	O	3(a)(38)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 3, 1985 in the office of the New York Secretary of State

3(a)(39)	O	3(a)(39)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed December 24, 1986 in the office of the New York Secretary of State

3(a)(40)	O	3(a)(40)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed June 1, 1987 in the office of the New York Secretary of State

3(a)(41)	O	3(a)(41)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed July 20, 1987 in the office of the New York Secretary of State


	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION			DESCRIPTION
3(a)(42)	O		3(a	)(42)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 27, 1988 in the office of the New York Secretary of State

3(a)(43)	O		3(a	)(43)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed September 27, 1990 in the office of the New York Secretary of State

3(a)(44)	O		3(a	)(44)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed October 18, 1991 in the office of the New York Secretary of State

3(a)(45)	O		3(a	)(45)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 5, 1994 in the office of the New York Secretary of State

3(a)(46)	O		3(a	)(46)	Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 5, 1994 in the office of the New York Secretary of State

3(a)(47)	V		3		Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed June 29, 1998 in the office of the New York Secretary of State

3(a)(48)	W		3		Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed March 19, 1999 in the office of the New York Secretary of State

3(a)(49)	AA		3.1		Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed November 29, 1999 in the office of the New York Secretary of State


	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION			DESCRIPTION
3(b)	U		3	(i)	By-Laws of Niagara Mohawk, as amended March 17, 1999

4(a)	O		4	(b)	Agreement to furnish certain debt instruments

4(b)(1)	C		**		Mortgage Trust Indenture dated as of October 1, 1937 between Niagara Mohawk (formerly CNYP) and Marine Midland Bank, N.A. (formerly named The Marine Midland Trust Company of New York), as Trustee

4(b)(2)	I		2-3		Supplemental Indenture dated as of December 1, 1938, supplemental to Exhibit 4(1)

4(b)(3)	I		2-4		Supplemental Indenture dated as of April 15, 1939, supplemental to Exhibit 4(1)

4(b)(4)	I		2-5		Supplemental Indenture dated as of July 1, 1940, supplemental to Exhibit 4(1)

4(b)(5)	D		7-6		Supplemental Indenture dated as of October 1, 1944, supplemental to Exhibit 4(1)

4(b)(6)	I		2-8		Supplemental Indenture dated as of June 1, 1945, supplemental to Exhibit 4(1)

4(b)(7)	I		2-9		Supplemental Indenture dated as of August 17, 1948, supplemental to Exhibit 4(1)

4(b)(8)	A		7-9		Supplemental Indenture dated as of December 31, 1949, supplemental to Exhibit 4(1)

4(b)(9)	A		7-10		Supplemental Indenture dated as of January 1, 1950, supplemental to Exhibit 4(1)

4(b)(10)	B		7-11		Supplemental Indenture dated as of October 1, 1950, supplemental to Exhibit 4(1)

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


	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
4(b)(11)	B	7-12	Supplemental Indenture dated as of October 19, 1950, supplemental to Exhibit 4(1)

4(b)(12)	E	4-16	Supplemental Indenture dated as of February 20, 1953, supplemental to Exhibit 4(1)

4(b)(13)	F	4-19	Supplemental Indenture dated as of April 25, 1956, supplemental to Exhibit 4(1)

4(b)(14)	G	2-23	Supplemental Indenture dated as of March 15, 1960, supplemental to Exhibit 4(1)

4(b)(15)	H	4-29	Supplemental Indenture dated as of July 15, 1967, supplemental to Exhibit 4(1)

4(b)(16)	J	4(b)(42)	Supplemental Indenture dated as of March 1, 1978, supplemental to Exhibit 4(1)

4(b)(17)	J	4(b)(46)	Supplemental Indenture dated as of June 15, 1980, supplemental to Exhibit 4(1)

4(b)(18)	K	4(b)(75)	Supplemental Indenture dated as of November 1, 1990, supplemental to Exhibit 4(1)

4(b)(19)	L	4(b)(77)	Supplemental Indenture dated as of October 1, 1991, supplemental to Exhibit 4(1)

4(b)(20)	M	4(b)(79)	Supplemental Indenture dated as of June 1, 1992, supplemental to Exhibit 4(1)

4(b)(21)	M	4(b)(81)	Supplemental Indenture dated as of August 1, 1992, supplemental to Exhibit 4(1)

4(b)(22)	R	4(b)(82)	Supplemental Indenture dated as of April 1, 1993, supplemental to Exhibit 4(1)

4(b)(23)	S	4(b)(83)	Supplemental Indenture dated as of July 1, 1993, supplemental to Exhibit 4(1)


	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION			DESCRIPTION
4(b)(24)	O		4	(86)	Supplemental Indenture dated as of July 1, 1994, supplemental to Exhibit 4(1)

4(b)(25)	T		4	(87)	Supplemental Indenture dated as of May 1, 1995, supplemental to Exhibit 4(1)

4(b)(26)	N		4(a	)(39)	Supplemental Indenture dated as of March 20, 1996, supplemental to Exhibit 4(1)

4(b)(27)	Q		4(b	)40	Supplemental Indenture dated as of November 1, 1998, supplemental to Exhibit 4(1)

4(c)	N		4(a	)(41)	Form of Indenture relating to the Senior Notes dated June 30, 1998

4(d)(1)	BB		1.2		Indenture, dated as of May 12, 2000, between Niagara Mohawk Power Corporation, a New York Corporation, and The Bank of New York, a New York banking corporation, as Trustee

4(d)(2)	BB		1.3		First Supplemental Indenture, dated as of May 12, 2000, between Niagara Mohawk Power Corporation, a New York corporation, and The Bank of New York, a New York banking corporation, as Trustee

4(d)(3)	CC		1.2		Form of Second Supplemental Indenture, between Niagara Mohawk Power Corporation and The Bank of New York, as Trustee

4(e)(1)	DD		4(e	)(1)	Supplemental Indenture, dated as of May 1, 2003, between Niagara Mohawk Power Corporation and HSBC Bank USA, as Trustee

4(e)(2)	DD		4(e	)(2)	First Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $100,000,000 Pollution Control Revenue Bonds, 1985 Series A


	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
4(e)(3)	DD	4(e)(3)	First Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $37,500,000 Pollution Control Revenue Bonds, 1985 Series B

4(e)(4)	DD	4(e)(4)	First Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $37,500,000 Pollution Control Revenue Bonds, 1985 Series C

4(e)(5)	DD	4(e)(5)	First Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $50,000,000 Pollution Control Revenue Bonds, 1986 Series A

4(e)(6)	DD	4(e)(6)	Second Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $25,760,000 Pollution Control Revenue Bonds, 1987 Series A

4(e)(7)	DD	4(e)(7)	Second Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $93,200,000 Pollution Control Revenue Bonds, 1987 Series B

4(e)(8)	DD	4(e)(8)	Second Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $69,800,000 Pollution Control Revenue Bonds, 1988 Series A

4(e)(9)	EE	4(e)(9)	Supplemental Indenture , dated as of December 1, 2003, between Niagara Mohawk Power Corporation and HSBC Bank USA, as Trustee


	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION			DESCRIPTION
4(e)(10)	EE		4(e	)(10)	First Supplemental Participation Agreement, dated as of December 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $45,600,000 Pollution Control Refunding Revenue Bonds, 1991 Series A

4(e)(11)	EE		4(e	)(11)	Supplemental Indenture, dated as of May 1, 2004, between Niagara Mohawk Corporation and HSBC Bank USA, as Trustee

4(e)(12)	EE		4(e	)(12)	Participation Agreement, dated as of May 1, 2004, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to Pollution Control Revenue Bonds, 2004 Series A

10(a)	Y		10.28		Master Restructuring Agreement dated July 9, 1997 among Niagara Mohawk and the 16 independent power producers signatory thereto

10(b)	Z		99-9		Power Choice settlement filed with the PSC on October 10, 1997

10(c)	P		10-13		PSC Opinion and Order regarding approval of the Power Choice settlement agreement with PSC, issued and effective March 20, 1998

10(d)	U		10	(c)	Amendments to the Master Restructuring Agreement

10(e)	Q		10-14		Independent System Operator Agreement dated December 2, 1999

10(f)	Q		10-15		Agreement between New York Independent System Operator and Transmission Owners dated December 2, 1999

10(g)	X		10-9		PSC Opinion and Order regarding approval of the sale of Nine Mile Point Nuclear Station Units No. 1 and No. 2

10(h)	X		10-10		Merger Rate Agreement reached among Niagara Mohawk, the PSC staff and other parties, filed with the PSC on October 11, 2001


	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION			DESCRIPTION
10(i)	GG		10	(y)	Severance Protection Agreement between New England Electric System and John G. Cochrane dated March 1, 1998

	*				Amendment to Severance Protection Agreement dated December 9, 1998

	*				Amendment to Severance Protection Agreement dated March 15, 2003

	*				Amendment to Severance Protection Agreement dated September 1, 2003

10(j)	*				Letter Agreement between National Grid USA and William F. Edwards dated January 16, 2002

	*				Agreement between National Grid USA and William F. Edwards effective as of March 15, 2005

10(k)	LL		4.5		Service Agreement among National Grid Transco plc, National Grid USA and Michael E. Jesanis dated July 8, 2004

10(l)	GG		10	(y)	Severance Protection Agreement between New England Electric System and Lawrence J. Reilly dated February 25, 1997

	*				Amendment to Severance Protection Agreement dated December 9, 1998

	*				Amendment to Severance Protection Agreement dated March 15, 2003

10(m)	*				Contract of Employment between The National Grid Company plc and Jeffrey A. Scott dated November 30, 1994

	*				Letter of Appointment between National Grid Transco plc and Jeffrey A. Scott dated June 5, 2003

	*				Temporary International Assignment Contract between The National Grid Group plc, The National Grid Company plc and Jeffrey A. Scott dated June 3, 2003

10(n)	HH		10	(l)	National Grid USA Companies’ Deferred Compensation Plan Amended and Restated December 6, 2001

	*				Amendment to National Grid USA Companies’ Deferred Compensation Plan dated April 1, 2002

	*				Amendment to National Grid USA Companies’ Deferred Compensation Plan dated September 1, 2003

10(o)	*				National Grid USA Companies’ Executive Severance Plan Amended and Restated March 1, 2003


	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION			DESCRIPTION
	*				Amendment to National Grid USA Companies’ Executive Severance Plan dated September 1, 2003

10(p)	HH		10	(n)	National Grid USA Companies’ Executive Supplemental Retirement Plan Revised and Restated December 21, 2001

	*				Amendment to National Grid USA Companies’ Executive Supplemental Retirement Plan dated February 1, 2002

	*				Amendment to National Grid USA Companies’ Executive Supplemental Retirement Plan dated August 1, 2003

	*				Amendment to National Grid USA Companies’ Executive Supplemental Retirement Plan dated September 1, 2003

10(q)	FF		10	(o)	New England Electric Companies’ Executive Retirees Health and Life Insurance Plan as Amended and Restated January 1, 1996

10(r)	*				National Grid USA Companies’ Incentive Compensation Plan as Amended and Restated March 1, 2003

	*				Amendment to National Grid USA Companies’ Incentive Compensation Plan dated September 1, 2003

10(s)	HH		10	(m)	National Grid USA Companies’ Retirement Supplement Plan Revised and Restated December 21, 2001

10(t)	KK		4.19		National Grid Transco Performance Share Plan 2002 (as approved July 23, 2002 by a resolution of the shareholders of National Grid Group plc, adopted October 17, 2002 by a resolution of the Board of National Grid Group plc, amended June 26, 2003 by the Share Schemes Sub-Committee of National Grid Transco plc, and amended May 5, 2004 by the Share Schemes Sub-Committee of National Grid Transco plc)

	JJ		4	(c)	National Grid Executive Share Option Plan 2002

	JJ		4	(c)	National Grid Group Share Matching Plan 2002

	II		4C		National Grid Executive Share Option Plan 2000

	II		4D		National Grid Executive Share Option Scheme

10(u)	*				Niagara Mohawk Long Term Incentive Plan as amended through September 28, 2000

10(v)	Q		10-24		Niagara Mohawk Supplemental Executive Retirement Plan Amended and Restated as of January 1, 1999


	INCORPORATION BY REFERENCE
EXHIBIT	PREVIOUS	PREVIOUS EXHIBIT
NO.	FILING	DESIGNATION	DESCRIPTION
	*		Amendment 1 to the Niagara Mohawk Supplemental Executive Retirement Plan dated December 17, 1999

	*		Amendment to Niagara Mohawk Supplemental Executive Retirement Plan dated August 17, 2001

21	*		Subsidiaries of the Registrant

31.1	*		Certification of Principal Executive Officer

31.2	*		Certification of Principal Financial Officer

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

Filed herewith.

NIAGARA MOHAWK POWER CORP /NY/ 10-K