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 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).

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 562,000 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).

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. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Regulatory Agreements and the Restructuring of the Regulated Electric Utility Business - Merger Rate Plan” for a detailed discussion of this rate plan.

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 Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Regulatory Agreements and the Restructuring of the Regulated Electric Utility Business” for a discussion of these initiatives.

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 and gas to its customers who are unable or unwilling to obtain an alternative supplier (which accounts for approximately 93% of the Company’s customers). 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.

As of March 31, 2004, 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 Organization, 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.

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.

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 Federal Energy Regulatory Commission (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).

General. 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 emissions, water discharges, site remediation, hazardous materials handling, waste disposal and employee health and safety. While the Company devotes considerable resources to environmental compliance and promoting employee health and safety, the impact of future environmental health and safety laws and regulations on the Company cannot be predicted with certainty.

In compliance with environmental statutes and consistent with its strategic philosophy, the Company performs environmental investigations and analyses and installs, as required, pollution control equipment, including, among other things, effluent monitoring instrumentation and materials storage/handling facilities designed to prevent or minimize releases of potentially harmful substances.

The Company believes it is probable that costs associated with environmental compliance will continue to be recovered through the ratemaking process. For a discussion of the circumstances regarding the Company’s continued 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.

Clean Air Act. See Item 3. Legal Proceedings, for a discussion of the potential liability for the past operations of Huntley and Dunkirk fossil generating stations.

ISO 14001. The Company’s Investment Recovery facility Environmental Management System (EMS) is certified to the International Organization for Standardization (ISO) 14001 standard. The Company’s distribution and transmission EMS are certified to the ISO 14001 standard. The NY Transmission System EMS has been integrated into the National Grid USA Transmission EMS.

Solid/Hazardous Waste. The public utility industry typically utilizes and/or generates in its operations a broad range of hazardous and potentially hazardous wastes and by-products. The Company believes it is handling identified wastes and by-products in a manner consistent with federal, state and local requirements and has implemented an environmental audit program to identify any potential areas of concern and aid in compliance with such 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. See Part II, Item 8. Financial Statements and Supplementary Data - Note D. Commitments and Contingencies, “Environmental Contingencies,” for a more detailed discussion of the Company’s environmental liabilities.

The Company’s New York work force at March 31, 2004 numbered approximately 5,500, of whom approximately 75 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.

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).

The Company has the following wholly-owned subsidiaries:

As of March 31, 2004, the Company’s electric transmission and distribution systems were composed of:

Only a part 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.

The Company distributes gas that it purchases from suppliers, and transports gas owned by others. As of March 31, 2004, 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

There are five Native American Nations with reservations located in the vicinity of the Company’s service territory and facilities. The Company has held discussions and has been involved in legal proceedings with Native American Nations involving the Company’s high voltage transmission facilities on Nation lands, provision of electric service to customers on Nation lands, and the Nations’ land claims.

In June 2000, the Company entered into a 40-year agreement with the Seneca Nation to settle issues related to approximately 50 miles of high voltage transmission and distribution facilities located on the Seneca Nation’s Cattaraugus and Allegheny Reservations. The Company has entered into federally approved Electric Service Agreements with the Onondaga, Tuscarora and Seneca-Tonawanda Nations governing the provision of electric service to customers on their lands. The Company intends to seek similar agreements with the Oneida and Mohawk Nations to supplement existing federally approved agreements. The Company’s facilities are potentially affected by land claim litigation involving the Cayuga, Oneida, Mohawk and Seneca Nations. A court has awarded damages to the Cayuga Nation that are payable by the State of New York. The land claim matters involving the Cayuga, Oneida, Mohawk and Seneca Nations have not been completely and finally resolved, although the St. Regis Mohawk Tribe recently entered into negotiations 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.

Substantially all of the Company’s operating properties are subject to a mortgage lien securing its mortgage debt.



ITEM 3. LEGAL PROCEEDINGS

The Company currently has the following material proceedings pending.

Alliance for Municipal Power v. New York State Public Service Commission: On February 17, 2003, the Alliance for Municipal Power (AMP) filed with the New York State Supreme Court (Albany County) a petition for review of decisions by the PSC that maintain the PSC’s established policy of using average distribution rates when calculating the exit fees that may be charged to municipalities that seek to leave the Niagara Mohawk Power Corporation system and establish their own municipal light departments. Changes in the methodology for the calculation of the exit fee are not likely to have a material effect on Niagara Mohawk’s financial position, results of operations or cash flows. However, AMP’s petition for review also challenges the lawfulness of Niagara Mohawk’s collection of exit fees from departing municipalities, regardless of the methodology used to calculate those fees. On October 27, 2003, the court dismissed AMP’s petition. AMP made a timely filing to appeal the court’s decision but has not perfected its appeal.

New York State v. Niagara Mohawk Power Corp. et al.: On January 10, 2002, the New York State Attorney General filed a civil action against Niagara Mohawk, NRG Energy, Inc. and certain of its 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. The State alleged that between 1982 and 1999, Niagara Mohawk modified the two plants 55 times without obtaining proper preconstruction permits and implementing proper pollution equipment controls.

On March 27, 2003, the court issued an order granting in part Niagara Mohawk’s motion to dismiss, which had been filed in 2002. Based on applicable statutes of limitations, the court reduced the number of projects allegedly requiring preconstruction permits under the Clean Air Act from fifty-five to nine.

On December 31, 2003, the court granted the State’s motion to amend the complaint, allowing it to assert operating permit violations against Niagara Mohawk and NRG. In so ruling, the court stated that monetary penalties for actions outside the statute of limitations period would still be barred. Niagara Mohawk answered the amended complaint on March 2, 2004, and filed a counterclaim against the State of New York in response to its common law public nuisance claim, seeking contribution for the Company’s portion of any alleged harm caused by emissions from facilities that the State owns or to which it has given permits. The State has moved to dismiss the counterclaim. Trial is scheduled for March 2006.

Niagara Mohawk Power Corporation v. NRG Energy, Inc., Huntley Power L.L.C. and Dunkirk Power L.L.C.: With respect to the claims asserted in the Clean Air Act lawsuit discussed above, NRG and its Affiliates have taken the position that Niagara Mohawk is responsible at least in part for the costs of pollution control equipment and related fines and penalties, notwithstanding contrary language in the agreement governing the sale of the Plants to the NRG Affiliates. As a result, on July 13, 2001, Niagara Mohawk sued NRG and the NRG Affiliates in New York State Supreme Court (Onondaga County), seeking a declaratory ruling that under the agreement, NRG is responsible for the costs of any pollution control upgrades and mitigation, as well as post-sale fines and penalties, that may result from the Clean Air Act suit. In response, NRG filed a counterclaim and filed a motion for partial summary on its counterclaim. Hearing on NRG’s motion is scheduled for July 28, 2004.

In addition to the legal proceedings described above, the Company has been named as a potentially responsible party (PRP) by either the United States Environmental Protection Agency or the New York Department of Environmental Conservation for numerous sites at which hazardous waste is alleged to have been disposed. There are significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. Management believes that hazardous waste liabilities for all sites of which it is aware are not material to the Company’s financial position. For more detail, see Note D “Commitments and Contingencies” in Item 8. Financial Statements and Supplementary Data.

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, 2004. On May 4, 2004, by unanimous written consent of the sole common stockholder,

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDERS MATTERS

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, and the Company sold no equity securities during the period covered by this Annual Report. 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.

The following tables set forth selected financial information for the Company for the years ended March 31, 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, and each of the three years during the period ended December 31, 2001. These tables have been derived from the financial statements of the Company, and should be read in connection therewith.

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

* 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.

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 “Merger Rate Plan”, below, for a discussion of the anticipated future results on the Company. 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 will retire by November 1, 2004, with the remainder retiring by November 1, 2007. The Company expensed approximately $19 million of VERO costs in the fiscal 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 $22 million and $30 million at March 31, 2004 and 2003, respectively.

Merger Rate Plan. On November 28, 2001, the PSC approved the Merger Rate Plan. This rate plan became effective on January 31, 2002, the closing of the merger. Key terms of the plan are as follows:

• Net customer savings of approximately $1 billion over the next ten years from the effective date of the plan, compared with rates projected without the merger.

• Price-stabilized commodity service for residential and commercial customers for several years.

• Agreement to forgo the collection of approximately $850 million in nuclear-related costs that otherwise would have been collected in rates.

• Permitted recovery of and a return on the Company’s regulatory assets, including stranded costs associated with the divestiture of generation assets under deregulation.

• Agreement to expand the Company’s annual upstate New York economic development efforts by $12.5 million.

• The extension by 16 months of the existing multi-year gas rate settlement agreement, resulting in a freeze in natural gas delivery rates through December 2004.

•Extension of the Low Income Customer Assistance Program and introduction of a special low-income rate.

• Establishment of a Service Quality Assurance Program that calls for up to $24 million in annual penalties or more under certain conditions, if defined customer service goals are not achieved.

Although rates will be lower under the Merger Rate Plan, the Company believes cost savings from the merger should enable it to improve its operating results.

Retail Bypass: In approving Power Choice, the rate plan in effect prior to the Merger Rate Plan, the PSC authorized changes to the Company’s retail tariff providing for the recovery of an exit fee for customers that leave the Company’s system. The retail tariff governs the application and calculation of the exit fee. The exit fee also applies to municipalities seeking to serve customers in the Company’s service area.

On September 22, 2002, a different type of retail bypass issue was presented in a filing with FERC by the NYISO seeking to implement a new station service rate which also provided that generators could net their station service electricity over a 30-day period. On November 22, 2002, FERC issued an order accepting the NYISO’s new rate, over the Company’s protest (the FERC NYISO Order). The FERC NYISO Order has allowed generators to argue that they should be able to avoid paying state-approved charges for retail deliveries when they take service under the NYISO tariff. On July 10, 2003, the Company filed modifications to its standby service rates with the PSC, which the PSC approved on November 25, 2003. The tariff modifications unbundle the transmission service component provided under the NYISO’s new rate but continue the Company’s own retail distribution charges to these customers.

A number of generators have complained or withheld payments associated with the Company’s delivery of station service to their generation facilities, including NRG Energy, Inc. (For a description of the NRG station service matter, see Item 8. Financial Statements and Supplementary Data, Note D. Commitments and Contingencies.) On December 23, 2003, FERC issued two orders on complaints filed by AES Somerset, L.L.C. (AES) and Nine Mile Point Nuclear Station, L.L.C. (Nine Mile) (together, the AES and Nine Mile FERC Orders), both of which are station service customers of the Company. The two orders allow these generators to net their station service electricity over a 30-day period and to avoid state-authorized charges for deliveries made over distribution facilities. While it is not entirely clear from reading the AES and Nine Mile FERC Orders, it is possible to construe them to have retroactive effect back to the date the plant was sold to AES by a third party. The net effect of these FERC decisions is that the two generators will no longer have to pay the Company for station service charges for electricity. The AES and Nine Mile FERC Orders are in direct conflict with the state-approved tariffs and the orders of the PSC on station service rates. The FERC orders, if upheld, will permit these generators to completely bypass the Company’s state-jurisdictional retail charges, including those set forth in the filing that was approved by the PSC on November 25, 2003. On February 23, 2004, the Company received orders granting rehearing for further consideration from the FERC in both the AES and Nine Mile Point proceedings. No further action on the rehearing requests has occurred to date.

On May 10, 2004, FERC issued an order denying motions for clarification filed by the Company and other parties with respect to the FERC NYISO Order, and reaffirmed its reasoning of the AES and Nine Mile FERC Orders. In so ruling, FERC indicated that the NYISO station service 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. The Company intends to appeal.

The AES and Nine Mile FERC Orders and FERC NYISO 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. 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.

Generation Asset Sales. Under deregulation, the Company divested all of its generation plants and operates primarily in the transmission and distribution sectors. The last generation asset sold was the Company’s share of the Nine Mile Point Nuclear Station for $603 million to Constellation in November 2001. The Company also signed PPAs with Constellation to purchase energy at negotiated prices through 2011 and revenue sharing agreements for ten years thereafter. See Item 8. Financial Statements and Supplementary Data, Note B. Rate and Regulatory Issues, Note D. Commitments and Contingencies, and Note L. Derivatives and Hedging Activities, for a further discussion of the terms of these agreements.

Following write-offs agreed to by the Company, the PSC approved the sale of Nine Mile Point and provided for the deferral and future recovery of the remaining nuclear stranded costs. The Company began to amortize the regulatory asset related to the loss on the sale of the nuclear assets immediately subsequent to such sale. Prior to implementation of the Merger Rate Plan, the Company had a regulatory asset of $1,074.6 million for the net loss on the sale of its nuclear generation assets. Under the Merger Rate Plan, the Company agreed to forgo collection of approximately $850 million in nuclear-related costs that otherwise would have been collected in rates. The nuclear regulatory asset that remained after such a write-off is included in the Company’s balance sheet as part of “Merger rate plan stranded costs.”

FERC Proceedings. The FERC has issued several orders and is contemplating some additional changes to the regulatory structure that governs the Company’s transmission business.

Standards of Conduct: FERC issued new regulations on November 25, 2003 revising the standards of conduct for transmission providers including National Grid. FERC’s regulations provide generally that transmission employees must function independently from marketing employees and from an Energy Affiliate. The definition of Energy Affiliate exempts holding and parent companies that do not engage in markets or transmission transactions in the US. However, language in the regulatory preamble implied that holding companies such as NGT would be “engaging in transmission transactions in the US” and, hence a non-exempt Energy Affiliate of the Company’s subsidiaries that are transmission providers. The Company filed a motion with FERC seeking to clarify the language so that it is clear that NGT is not an Energy Affiliate of the Company’s transmission subsidiaries. On April 16, 2004 FERC revised its regulations. The preamble to the revised regulations clarifies that a holding and parent company such as NGT qualifies for an exemption to the definition of Energy Affiliate. The Company’s Granite State Electric subsidiary falls within the technical definition of an Energy Affiliate because it is a company not engaged in transmission that makes a wholesale power sale. We have asked FERC for a waiver of its rules with respect to Granite State, however, pointing out that Granite State has no financial interest in its wholesale power sale. The regulations do not create any significant new financial risks for us.

PSC Issues. In February 2004, the Company reached an agreement with PSC Staff that would provide rate recovery for approximately $15 million of the $30 million pension settlement loss incurred in fiscal 2003. This agreement is subject to approval by the full New York State Public Service Commission. In addition, the agreement covers the funding of the entire settlement loss to benefit plan trust funds. Under the agreement, the Company will fund the non-recoverable portion of this loss within 30 days of approval of the agreement. The Company plans to file a petition with the PSC seeking recovery of its fiscal year 2004 settlement losses as well. For further discussion of the settlement losses see Item 8. Financial Statements and Supplementary Data - Note H. Employee Benefits.

In August 2003, the 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 during fiscal 2003 and an additional $209 million of tax-deductible funding by the end of fiscal 2004. Under the settlement, the Group 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. This settlement resolves all PSC staff audit issues related to the pre-acquisition period with the exception of certain gas deferrals and a Staff review of a pending Company compliance filing related to the sale of the Nine Mile Nuclear Station.

As part of the Company's ongoing reconciliation of commodity costs and revenues, the Company has identified several adjustments and included them in filings with the PSC.  Specifically, the Company has 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 is proposing to refund $24 million associated with other revenues that were not included in the commodity adjustment reconciliation. This filing is pending before the PSC, and the Company cannot predict the outcome of the filing.

On February 19, 2003, the PSC commenced a proceeding to create a renewable portfolio standard for New York State, establishing a working target that 25% of the energy retailed in New York would be generated from qualifying renewable resources. An administrative law judge issued a recommended decision on June 3, 2004 for review by the full Commission. The decision proposes that an incremental amount of 7.5% renewable resource energy (13.7 Million MWhs) be retailed in New York State by 2013 or later, depending on the results of a proposed Commission review in 2008. If the Commission adopts the recommendations, individual load-serving entities such as Niagara Mohawk would have to comply with annual program targets beginning in 2006. The decision contemplates that utilities would have an opportunity to recover program costs in rates, subject to prudence reviews. The Commission will receive public comments on the recommendations before rendering any decision.

During fiscal 2004, the PSC issued an order related to the potential sale of a Company building. The order addresses the sharing between customers and the Company of sales proceeds and future avoided costs that will result from disposal of the building, as well as the sharing of the transaction costs and remaining net book value of this facility. In its order, the PSC has directed the Company to share with customers 50% of the benefits and costs associated with the sale, including the undepreciated net book value of the building. As of March 31, 2004, the sale of this facility remains subject to future performance by the proposed purchaser, and as such, the Company has not recorded the potential effects of this transaction in its records. Upon completion of the sale of this building, the Company will record a net charge of approximately $3 million (pre-tax) to expense reflecting its net unrecovered cost of this facility. The order also directs the Company to follow the same accounting and ratemaking treatment for the sale of other buildings during the term of the Merger Rate Plan.

Change of Fiscal Year. 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 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 costs typically include deferral of energy costs, 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 included 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.

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 for years.

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. 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.

The Company has received approval from the PSC to establish a regulatory asset or liability derivative instruments that did not qualify for hedge accounting and were the result of regulatory rulings.

The following discussion and analysis highlights items that significantly affected the Company’s operations during the years ended March 31, 2004 and 2003, the three months ended March 31, 2002 and 2001, and the year ended December 31, 2001. See “Merger Rate Plan” for a further discussion of how the closing of the merger with National Grid has or will impact the current and future results of the Company. Results of operations through January 30, 2002 reflect the Power Choice rate plan and the Company’s generation assets sales. Reported earnings under Power Choice were substantially depressed as a result of the regulatory treatment of the Stranded cost regulatory asset. Information relating to all “predecessor” periods prior to the acquisition is presented using the Company’s historical basis of accounting. It should also be read in conjunction with Item 8. Financial Statements and Supplementary Data, and other financial and statistical information appearing elsewhere in this report.

Beginning with the merger in January 2002, the Company now reports results on a fiscal year ending March 31. To assist in the comparability of the Company’s financial results and discussions, results of operations for the three months ended March 31, 2002 include results for the 30 day period of the predecessor and the 60 day period of the successor and are designated as “combined.” Management has based its discussion and analysis of results of operations for the year ended March 31, 2003 as compared to the year ended December 31, 2001. Management has also based its discussion and analysis of results of operations for the three month period ending March 31, 2002 as compared to the three month period ending March 31, 2001 on the combined results of operations for the three month period ending March 31, 2002.

EARNINGS

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.

Net income for the fiscal year ended March 31, 2003 increased approximately $107 million compared to the year ended December 31, 2001. This increase is primarily due to the implementation of the Merger Rate Plan and a $123 million write-off in 2001 in connection with the sale of the Company’s nuclear assets, which was completed in 2001. Under the Merger Rate Plan, the Company has lowered delivery rates leading to lower operating revenues. However, this has been offset by lower operating expenses as a result of merger savings, the sale of the generation business and lower interest expense due to refinancing and the continuing repayment of debt.

Net income for the three months ended March 31, 2002 was approximately $24 million lower than the three month period ended March 31, 2001. A decline in operating income due to the effect a warm winter had on the gas business and increased other operation and maintenance costs was partially offset by lower interest expense due to the repayment of debt during 2002.

REVENUES

Electric revenues decreased $27 million during the year ended March 31, 2004 from the prior year. Electric revenues decreased $82 million in the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001. The table below details components of this fluctuation.

The decrease in retail sales for year ended March 31, 2004 from the comparable period in prior year was primarily attributable to a decrease in electric kilowatt-hour (KWh) deliveries (see below). Volume growth, primarily in the residential sector partially offset these decreases. Regulatory asset revenue comparisons were also affected by anticipated reductions in the return on regulatory assets and lower purchase power costs (due to lower demand).

The decrease in sales for resale for the twelve-months ended March 31, 2003 as compared to the twelve month ended December 31, 2001 is primarily attributable to lower sales to the NYISO. Transmission delivery revenue was lower primarily due to lower NYISO Transmission Congestion Contracts (TCC) auction revenues. Retail sales revenues increased due to higher delivery only revenue by $88 million, but were almost entirely offset by lower electric rates under the Merger Rate Plan.

Electric revenues decreased $1 million in the three months ended March 31, 2002 as compared to the same period in the 2001.

Electric kilowatt-hour sales were approximately 38.3 billion and 38.8 billion for the year ended March 31, 2004 and 2003, 9.4 billion and 9.3 billion for the three months ended March 31, 2002 and the same period in 2001, respectively, and 39.9 billion in the calendar year 2001.

Electric deliveries decreased 0.5 billion KWh for the year ended March 31, 2004 from the prior year. The decrease is primarily due to a return of more normal weather in the current fiscal year, versus the more extreme weather last year, particularly in the summer months. Offsetting this decrease was strong residential Kwh sales growth of 4.6%. Electric deliveries for the twelve-months ended March 31, 2003 as compared to the twelve months ended December 31, 2001 decreased 1.1 billion KWh. The decrease is primarily due to a decrease in sales for resale of 2.1 billion KWh as a result of lower sales to the NYISO and lower sales to commercial and industrial customers of 2.1 billion KWh offset by increased residential sales of 0.6 billion KWh and an increase in delivery only of energy of 2.5 billion KWh.

Electric deliveries for the three months ended March 31, 2002 as compared to the same period in 2001 increased 0.1 billion KWh and increased 3.6 billion KWh in the calendar year 2001 as compared to the same period in 2000. The increase in the three months ended March 31, 2002 as compared to the same period in 2001 is primarily due to an increase in sales for resale of 0.7 billion KWh as a result of higher sales to the NYISO and an increase in distribution of energy of 0.2 billion KWh, partially offset by a decrease in sales to ultimate customers of 0.7 billion KWh primarily due to the milder weather.

Gas revenues increased $71 million in the fiscal year ended March 31, 2004 from the prior year. This increase is primarily a result of higher prices of gas purchases, which are being passed through to customers. Partially offsetting these increases was an $8.0 million adjustment related to state income tax revenue deferrals.

Gas revenues decreased $13 million for the twelve-months ended March 31, 2003 compared to the twelve-months ended December 31, 2001 primarily due to a decrease in the commodity cost of purchased gas offset somewhat by an increase in delivery revenue. The primary reason for the increase in delivery revenue is higher rates which reflect the inclusion of the state income tax in the rates charged to customers. The decrease in the cost of purchased gas is explained below under “gas purchased” expense.

The table below details components of the gas revenue fluctuation:

Gas revenues decreased $127 million in the three months ended March 31, 2002 from the comparable period in 2001 due to lower purchased gas prices and milder weather in 2002.

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 for the twelve months ended March 31, 2004, excluding transportation of customer-owned gas, decreased approximately 3.6 million Dekatherms (Dth), or a 2 percent decrease from the prior year, primarily due to reduced deliveries to electric generation customers. Gas sales for the twelve months ended March 31, 2003, excluding transportation of customer-owned gas and spot market sales, were 69 million Dth, a 5.8 percent increase from the twelve-months ended December 31, 2001. The increase was primarily due to the impacts of weather as offset by migration to delivery only service. Gas sales in the calendar year 2001, excluding transportation of customer-owned gas and spot market sales, were 64 million Dth. Gas sales in the three months ended March 31, 2002, excluding transportation of customer-owned gas and spot market sales, were 28 million Dth, a 19.6 percent decrease from the same period in 2001. The decrease was primarily due to milder weather in the three months ended March 31, 2002 as compared to the same period in 2001.

OPERATING EXPENSES

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 last year. In addition, contractual obligations to certain higher cost suppliers expired in the fiscal 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 electricity increased $290 million for the year ended March 31, 2003 as compared to the year ended December 31, 2001, $52 million in the three months ended March 31, 2002 as compared to the same period in 2001, primarily as a result of the timing of the various sales of the Company’s generation assets. The Company now purchases all of its load requirement through the NYISO, or from other parties under long-term PPAs (for a discussion of the portion of the purchases that are hedged. Although the prices the Company must pay for electricity are higher than the fuel costs it incurred when the assets were owned, the Company avoids operating costs from running these plants, including labor, fuel, real estate taxes, and depreciation.

Significantly higher natural gas prices impacted the Company’s fuel and purchased power costs in early 2001, principally because restructured contracts with IPPs began indexing to natural gas prices in July 2000. Fuel and purchased power costs were also higher in early 2001 because of an indexed contract with the new owner of the Albany generating station and an indexed contract with an IPP not part of the Master Restructuring Agreement (MRA). The Albany station is fueled by oil or natural gas. With respect to its exposure to the restructured contracts with the IPPs and the Albany contract, the Company takes steps to hedge against further volatility in natural gas prices, largely by purchasing New York Mercantile Exchange (NYMEX) gas futures contracts. On September 1, 2001, the rate plan changes under the Power Choice rate agreement allowed for the pass-through of most commodity-related costs to customers. This pass-through of commodity costs to customers continues under the Merger Rate Plan.

IPP purchases decreased by $17 million in the three months ended March 31, 2002 as compared to the same period in 2001, since the Company entered into an agreement with one IPP that reduced the amount of energy it had to buy from them. In the three months ended March 31, 2001, the Company paid that IPP $18 million. The Company did not make any payments to that particular IPP in the same period in 2002.

The Company had no fuel for electric generation expense in either the twelve-months ended March 31, 2004 and 2003 or the three months ended March 31, 2002 because it had sold all of its generation assets in earlier periods.

Purchased gas expense increased approximately $85 million for the year ended March 31, 2004 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 $6.61 in the year ended March 31, 2004 from $5.57 in the prior year. This increase in price was slightly offset by decreased purchases. Quantities purchased and withdrawn from storage were down 3.6 million Dth.

Purchased gas expense decreased approximately $26 million for the twelve-months ended March 31, 2003 as compared to the twelve-months ended December 31, 2001. The decrease is a result of lower gas prices in the twelve-months ended March 31, 2003 partially offset by increased sales attributable to the colder winter 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, decreased to $5.57 in the twelve-months ended March 31, 2003 from $6.45 for the twelve-months ended December 31, 2001. Quantities purchased and withdrawn from storage were up 5.7 million Dth.

Purchased gas expense decreased $120 million in the three months ended March 31, 2002 as compared to the same period in 2001 primarily as a result of lower natural gas prices. The Company’s net cost per Dth, as charged to expense, including the effects of the gas commodity cost adjustment clause, decreased to $3.97 in the three months ended March 31, 2002 from $7.53 the same period in 2001. Dth purchased and withdrawn from storage were down 0.4 million Dth.

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 $49 million for the year ended March 31, 2004 from the prior year. The table below details components of this fluctuation.

After the merger with National Grid, the Company modified its method of reserving for accounts receivable accounts with balances greater than 90 days in arrears. The Company recorded a charge of $19 million to write-off certain projects in its construction work-in-process (CWIP) accounts. This charge was the result of a post-merger review of pre-merger CWIP projects.

Other operation and maintenance expense decreased $112 million for the year ended March 31, 2003 as compared to the year ended December 31, 2001. The decrease is primarily attributable to the sale of its generation assets, especially its nuclear generation, in that the labor, fuel, and real estate taxes for these generation assets are no longer paid for. Expense was also reduced due to lower transmission costs from fewer TCCs purchased from NYISO and merger integration savings in the current period. TCCs confer the right to collect or obligation to pay congestion charges for a single megawatt of energy transmitted between two geographic locations.

Other operation and maintenance expense for the Company had increased $27 million in the three months ended March 31, 2002 as compared to the same period in 2001, primarily as a result of increased employee welfare expense due to separation costs of $7 million, increased pension and other postretirement benefits expense of $14 million, increased compensation accruals of $6 million, incremental merger related costs of approximately $11 million, incremental storm expense of $14 million and a higher systems benefit charge of $6 million. The systems benefits charge is offset in electric revenues. These increases were partially offset by lower nuclear operation expense of $36 million as a result of the sale of the nuclear assets.

In 2001, the Company recorded a non-cash write-off of $123 million before tax, which is reflected on the disallowed nuclear investment costs line item in accordance with the PSC Order approving the sale of the nuclear assets.

Depreciation and amortization increased approximately $2 million for the year ended March 31, 2004 from the prior year, primarily due to plant acquisitions. Depreciation and amortization expense decreased approximately $94 million for the year ended March 31, 2003 as compared to the year ended December 31, 2001, and decreased approximately $28 million in the three months ended March 31, 2002 as compared to the same period in 2001, primarily as a result of the sale of the Company’s generation assets at various times during 1999 through 2001.

Amortization of stranded costs increased $45 million for the year ended March 31, 2004 from the prior year in accordance with the merger rate plan. Amortization of stranded costs decreased $244 million for the twelve-months ended March 31, 2003 as compared to the twelve-months ended December 31, 2001, decreased by $27 million in the three months ended March 31, 2002 as compared to the same period in 2001. These changes result from the difference in rate plans. Under Power Choice (in effect prior to January 31, 2002), the stranded cost regulatory asset was being amortized ratably over a ten year period that was expected to end in August 2008. Under the Merger Rate Plan (which became effective on January 1, 2002) the stranded cost regulatory asset amortization period was increased to cover 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 $26 million for the year ended March 31, 2004 from the prior year. This decrease is primarily due to a $31 million reduction of Gross Receipts Tax (GRT) as a result of lower GRT rates offset by increased property taxes of $9 million.

Other taxes increased approximately $19 million for the year ended March 31, 2003 as compared to the year ended December 31, 2001, due to a decrease in the GRT Power for Jobs tax credit. In 2001, the Company amended its 1998 through 2000 tax returns, thereby increasing the amount of Power for Jobs credit it recorded in 2001. This increase was partially offset by a reduction in property taxes primarily resulting from the sale of the nuclear assets in November 2001.

Other taxes increased $11 million in the three months ended March 31, 2002 as compared to the same period in 2001. In the first three months ended March 31, 2001, the Company received $22 million in GRT Power for Jobs credits due to a prior year true-up to actual filed returns. GRT credits of $1.2 million were received in the same period in 2002 due to a prior year true-up. This increase was partially offset by a reduction in the GRT tax rate of $6 million and a reduction in property taxes of $4 million primarily resulting from the sale of the nuclear assets in November 2001.

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. Income taxes increased $84 million for the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001. The increase is due primarily from increased book taxable income for the twelve months ended March 31, 2003 and an accrual to return true-up of $7 million. Income taxes increased approximately $6 million in the three months ended March 31, 2002 primarily due to higher book taxable income. See Item 8. Financial Statements and Supplementary Data, - Note G. Federal and State Income Taxes, for a reconciliation of the tax computed at the statutory rate.

OTHER INCOME (DEDUCTIONS), INTEREST AND PREFERRED DIVIDENDS

Other income (deductions) decreased $8 million for the year ended March 31, 2004 from the prior year 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.

Other income (deductions) decreased $74 million for the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001. This is primarily attributable to the Company recording $80 million of previously deferred investment tax credits related to the sale of the nuclear assets in 2001.

Other income (deductions) in the three months ended March 31, 2002 decreased $4 million primarily due to carrying charges on IPP buy out contract adjustments of $2 million and, in the three months ended March 31, 2001, other income reflected the recording of a non-cash incentive related to generation asset sales of $7 million for which there was no corresponding amount in the three months ended March 31, 2002.

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 the current year 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 is no corresponding charge in the current period.

Interest charges decreased $33 million in the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001 and $13 million in three months ended March 31, 2002 as compared to the three months ended March 31, 2001, mainly due to the repayment and early repayment of debt and, to a lesser extent, lower interest rates.

Preferred dividends decreased $1 million for the year ended March 31, 2004 from the prior year due to redemptions. Preferred dividends decreased $25 million in the twelve months ended March 31, 2003 from the twelve months ended December 31, 2001 due to preferred stock redemptions.

The Company is especially 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” below for a discussion of the Company’s future capital requirements.

Short Term. At March 31, 2004, the Company’s principal sources of liquidity included cash and cash equivalents of $27 million and accounts receivable of $579 million. The Company has a negative working capital balance of $717 million primarily due to long-term debt due within one year of $533 million and short-term debt to affiliates of $464 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 from operating activities was $349 million for the Company for the year ended March 31, 2004 which funded its acquisition of utility plant and the retirement of certain debt obligations.

The Company’s net cash used in investing activities increased $286 million for the year ended March 31, 2004 from the comparable period in the prior year. This increase was primarily as a result of a one-time cash inflow of $250 million in the prior fiscal year from a note related to the generation asset sale.

The Company’s net cash used in financing activities decreased $526 million for the year ended March 31, 2004 from the comparable period in prior year. This decrease results from an equity contribution from Holdings of $309 million in the current year, a dividend to Holding of $150 million in the prior year, and a decrease of approximately $81 million in overall debt reductions from the prior year. The $309 million in the current period from Holdings was used to fund contributions to the pension and post-retirement trusts.

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 $533 million at March 31, 2004. In addition, construction expenditures planned within one year are estimated to be $266 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:

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 during fiscal 2004. Under the settlement, the Group 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.

In addition to the funding provided in respect of the settlement referred to above, other contributions to the pension and post-retirement trusts were higher in the current fiscal year than in the prior in connection with the Company’s VEROs.

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, 2004, the Company had approximately $1.5 billion in such first mortgage bond maturities and early redemptions. This is expected to increase to over $1.7 billion in 2006 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. Niagara Mohawk's interest in the power plant was sold to Constellation Nuclear, LLC in 2000. Constellation agreed to provide a certificate at closing which obligated them to maintain the covenants contained in the sale and purchase agreement that require Constellation to maintain the pollution control assets in a tax exempt manner, thus providing the Company the ability to call and refund the bonds.

On December 17, 2003, the Company completed a tender offer for $45.6M of 6 5/8% tax exempt bonds due 2013. The bonds were subsequently reissued in auction rate mode.

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, which allowed the Company to terminate the $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.

New Accounting Standards:
In June 2001, the Financial Accounting Standards Boards (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). FAS 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. FAS 143 is effective for fiscal years beginning after June 15, 2002. The Company adopted FAS 143 during the fiscal year ended March 31, 2004.

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.

The cost of removal collected from customers has historically been embedded within accumulated depreciation (as these costs have charged over time through depreciation expense). With the adoption of FAS 143 the Company has reclassified the 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 $314 million and $307 million for cost of removal through March 31, 2004 and 2003, respectively.

In December 2003 the FASB revised SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (FAS 132-R). FAS 132-R retains the disclosure requirements contained in the original statement and requires new disclosures about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension and other defined benefit postretirement plans. FAS 132-R is effective for fiscal years ending after December 15, 2003 and for interim periods beginning thereafter. The Company has adopted FAS 132-R during the current fiscal year. This standard does not change the measurement or recognition of the aforementioned plans and, as such, the adoption of this statement has not had any effect on the Company’s financial position, results of operations, or cash flows.

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of ARB 51” (FIN 46). FIN 46 requires the consolidation of entities in which an enterprise absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interest in the entity. Historically, entities have generally been consolidated by an enterprise when it has a controlling financial interest through ownership of a majority voting interest in the entity. The objectives of FIN 46 are to provide guidance on the identification of Variable Interest Entities (VIEs) for which control is achieved through means other than a controlling financial interest, and how to determine which business enterprise, as the primary beneficiary, should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the entity lacks sufficient equity to absorb expected losses without additional subordinated financial support or (2) its at-risk equity holders as a group are not able to make decisions that have a significant impact on the success or failure of the entity’s ongoing activities.

In December 2003, the FASB modified FIN 46 with FIN 46-R to make certain technical corrections to the standard and to address certain implementation issues. FIN 46, as originally issued, was effective immediately for VIEs created or acquired after January 31, 2003. FIN 46-R delayed the effective date of the interpretation to no later than March 31, 2004, (for calendar-year enterprises), except for Special Purpose Entities for which the effective date was December 31, 2003. The adoption of FIN 46-R has not had a material impact on the Company's financial position, results of operations, or cash flows.

In January 2004, the FASB issued Staff Position No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act)” (FSP 106-1). FSP 106-1 is effective for annual fiscal periods ending after December 7, 2003. FSP 106-1 permits employers that sponsor postretirement benefit plans (plan sponsors) that provide prescription drug benefits to retirees to make a one-time election to defer accounting for any effects of the Act. FSP 106-1 requires all plan sponsors to provide certain disclosures, regardless of whether they choose to account or defer accounting. If deferral is elected, the deferral must remain in effect until the earlier of (1) the issuance of guidance by the FASB on how to account for the federal subsidy to be provided to plan sponsors under the Act or (2) the remeasurement of plan assets and obligations subsequent to January 31, 2004. The Company has decided not to make an election until further accounting guidance is issued by the FASB. The measurement of the accumulated postretirement benefit obligation and net postretirement benefit cost in the financial statements and accompanying notes do not reflect the effect of the Act on the Company's postretirement benefit plans.

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. The EPRMC issues and oversees the Financial Risk Management Policy (the Policy) that 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 a 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. Bank Credit Arrangements. At March 31, 2004, the company had converted its daily adjustable rate pollution control revenue bond program to an auction rate mode and terminated the letter of credit facility. At March 31, 2003 the Company had no outstanding balance on the revolving credit facility. The adjustable rate promissory notes are currently valued at $413.8 million. An issue of fixed-adjustable rate preferred stock is fixed at 6.9 percent annual dividend rate for the first 5 years (ending in 2004) then adjusts and is not considered adjustable for this analysis. There are $464 million of short term borrowing at March 31, 2004 from the inter-company money pool maintained by National Grid. At March 31, 2003 these borrowings totaled $198 million.

There is no interest rate cap on the promissory notes. The interest on the revolving credit facility is variable, and tied to the London Interbank Offered rate, plus a number of basis points predicated on the amount of the borrowing. As stated, currently, there are no borrowings under this facility.

The interest rates on short term borrowings are tied to the published, 30 day, commercial paper rate with the amount borrowed from National Grid adjusted monthly.

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, 2004 and 2003, adjustable rate instruments comprise 12.8 percent and 8.8 percent of total capitalization, respectively. For the same periods, the revolving credit facility and promissory notes are 10.3 percent and 9.1 percent of total long-term debt. The proportion of adjustable instruments to total capitalization increased because of increased borrowings from the money pool. In the aggregate at March 31, 2004 and 2003 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 2004, the Company’s interest expense would increase and income before taxes would decrease by approximately $8.8 million. This figure was derived by applying a hypothetical 1 percent variance to the variable rate debt of $413.8 million plus the short-term variable borrowings of $464 million at March 31, 2004. 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. 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-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.

In addition, many large customers that continue to purchase electricity from the Company have agreed to take market price risk, further lowering commodity risk. For the remaining customers that have firm prices, the Company has hedged a significant portion of the commodity costs through various physical and financial contracts. As these contracts expire, customers who buy electricity from the Company will bear the commodity price risk for energy associated with the expiring contracts. Increases in the cost of natural gas, primarily as it is used as a fuel in electricity generation, raises issues surrounding the ability for ratepayers to absorb such price volatility. 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.

As part of the MRA, the Company entered into restated indexed swap contracts with eight IPPs. The company had also entered into financial swap agreements associated with the sales of the Huntley, Dunkirk, and Albany generating stations which expired in fiscal 2004. 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 $715.4 million and $793.0 million at March 31, 2004 and 2003, respectively, and is recorded on the Company’s balance sheets as a “Liability for swap contracts.” The decrease is primarily due to a lowering of the discount rate plus a revaluation of the contracts indicating higher forecasted contract prices. These increases were somewhat offset by normal contract settlements. 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 $14.4 million increase or decrease in the present value of the projected over-market exposure. If the market prices were to increase or fall by 1 percent, the Company would see a $7.4 million decrease or increase in the projected over-market exposure. If the discount rate were one half percent higher or lower, the net present value of the projected over market exposure would decrease or increase by approximately $8.4 million.

The area of exposure to cash flow is in the indexing of the contract prices for the IPP indexed swaps and the Albany swap (Huntley and Dunkirk have fixed contract prices) and a non-MRA IPP where payments are based on gas prices. The contract payments under the IPP and Albany swaps and the non-MRA IPP are indexed to the costs of fuel, primarily natural gas; Albany can be oil or 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 and Albany 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.
Even with the regulatory recovery of the cost of these contracts, the Company believes it is prudent to hedge these payments. For the period ended March 31, 2004, gas futures were purchased to hedge approximately 50 percent of the amount needed to offset gas price changes.

At March 31, 2003, the open NYMEX futures the Company had in place to hedge the payments under these contracts had a fair value gain of $14.2 million.

Activity for the fair value of the NYMEX futures and gas basis swaps for the 12 months ended March 31, 2004, is as follows:

Gas Supply Price Risk: The cost of natural gas sold to customers fluctuates during the year with prices historically most volatile in the winter months. The Company’s gas rate agreement includes a provision for the collection or pass back of increases or decreases in purchased gas costs. The PSC has also mandated that the Company attempt to reduce the price volatility in the gas commodity portion of customers’ bills. In response to this mandate, the Company’s Board of Directors has authorized the use of futures, options, and swaps to hedge against gas price fluctuations. The hedging program will be consistent with the Financial Risk Management Policy and will be 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, 2003 the Mark to Market net open position of cash flow hedges for gas supply was a gain of $1.3 million. There were 179 open futures contracts and 369 open options at March 31, 2003.

The following table details the fair value activity for gas cash flow hedges for the 12 months ended March 31, 2004:

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. The Company did not use electricity swaps during the year ended March 31, 2003. In April 2003, the Company began utilizing NYMEX electricity swap contracts to hedge electricity purchases for the summer 2003. The Company continues to evaluate the use of hedging instruments to manage the cost of electricity purchased. At March 31, 2004, there were no open electricity futures contracts.

Equity Price Risk. With the sale of the nuclear generating stations on November 7, 2001 and the associated transfer of all decommissioning trust fund assets to the new owners, the Company eliminated its equity price risk.

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income (loss), of retained earnings and of cash flows present fairly, in all material respects, the financial position of Niagara Mohawk Power Corporation and its subsidiaries at March 31, 2004 and 2003, and the results of their operations and their cash flows for each of the two years in the period ended March 31, 2004 and the sixty day period ended March 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements 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 6, 2004, except for Notes
D and E, as to which the dates
are May 10, 2004 and May 27, 2004,
respectively

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

In our opinion, the accompanying consolidated statements of operations, of comprehensive income (loss), of retained earnings and of cash flows present fairly, in all material respects, the results of operations and cash flows of Niagara Mohawk Power Corporation and its subsidiaries for the thirty day period ended January 30, 2002 and for the year ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements 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 14, 2002

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.