For the transition period from __________ to __________

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q - For the Quarter Ended September 30, 2003

Note A – Summary of Significant Accounting Policies

Basis of Presentation: Niagara Mohawk Power Corporation and subsidiary companies (the “Company”), in the opinion of management, have included all adjustments (which include normal recurring adjustments) necessary for a fair statement of the results of operations for the interim periods presented. The March 31, 2003 condensed balance sheet data included in this quarterly report on Form 10-Q was derived from audited financial statements included in the Company’s Annual Report on Form 10-K for the year ended March 31, 2003. As such, the March 31, 2003 balance sheet included in this Form 10-Q is considered unaudited as it does not include all the footnote disclosures contained in the Company’s Form 10-K. These financial statements and the notes thereto should be read in conjunction with the audited financial statements included in the Company’s Annual Report on Form 10-K for the year ended March 31, 2003.

The Company’s electric sales tend to be substantially higher in summer and winter months as related to weather patterns in its service territory; gas sales tend to peak in the winter. Notwithstanding other factors, the Company’s quarterly net income will generally fluctuate accordingly. Therefore, the earnings for the three-month and six-month periods ended September 30, 2003 should not be taken as an indication of earnings for all or any part of the balance of the year.

The Company is a wholly owned subsidiary of Niagara Mohawk Holdings, Inc. (“Holdings”) and, indirectly, National Grid Transco plc.

Restricted Cash: Restricted cash consists of margin accounts for hedging activity, health care claims deposits, New York State Department of Conservation (“DEC”) securitization for certain site cleanup, and worker’s compensation premium deposit.

Reclassifications: Certain amounts from prior years have been reclassified in the accompanying consolidated financial statements to conform to the current year presentation.

Note B – Rate and Regulatory Issues

The Company’s financial statements conform to Generally Accepted Accounting Principles, including the accounting principles for rate-regulated entities. Substantively, SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” permits a public utility, regulated on a cost-of-service basis, to defer certain costs, which would otherwise be charged to expense, when authorized to do so by the regulator. These deferred costs are known as regulatory assets, which in the case of the Company, are approximately $5.4 billion at September 30, 2003. These regulatory assets are probable of recovery under the Company’s Merger Rate Plan and Gas Multi-Year Rate and Restructuring Agreement. The Company believes that the regulated cash flows to be derived from prices it will charge for electric service in the future, including the Competitive Transition Charges (“CTCs”), and assuming no unforeseen reduction in demand or bypass of the CTC or exit fees, will be sufficient to recover the Merger Rate Plan stranded regulatory assets over the planned amortization period with a return. Under the Merger Rate Plan, the Company’s remaining electric business (electric transmission and distribution business) continues to be rate-regulated on a cost-of-service basis and, accordingly, the Company continues to apply SFAS No. 71 to these businesses. Also, the Company’s Independent Power Producer (“IPP”) contracts, and the Purchase Power Agreements entered into in connection with the generation divestiture remain recoverable from customers.

In the event the Company determines, as a result of lower than expected revenues and/or higher than expected costs, that its net regulatory assets are not probable of recovery, it can no longer apply the principles of SFAS No. 71 and would be required to record an after-tax, non-cash charge against income for any remaining unamortized regulatory assets and liabilities. If the Company could no longer apply SFAS No. 71, the resulting charge would be material to the Company’s reported financial condition and results of operations.

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

Stranded Costs: Under the Merger Rate Plan, a regulatory asset was established that included the costs of the Master Restructuring Agreement (“MRA”), the cost of any additional IPP contract buyouts and the deferred loss on the sale of the Company’s generation assets. The MRA represents the cost to terminate, restate or amend IPP contracts. The Company is also permitted to defer and amortize the cost of any new IPP contract buyouts. Beginning January 31, 2002, the Merger Rate Plan stranded costs regulatory asset is being amortized unevenly over ten years with larger amounts being amortized in the latter years, consistent with projected recovery through rates.

Note C – Contingencies

Environmental Contingencies: 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.

The Company is currently aware of 115 sites with which it may be associated, including 61 which are Company-owned. With respect to non-owned sites, the Company may be required to contribute some proportionate share of remedial costs. Although one party can, as a matter of law, be held liable for all of the remedial costs at a site, regardless of fault, in practice costs are usually allocated among Potentially Responsible Parties (“PRPs”). The Company has denied any responsibility at certain of these PRP sites and is contesting liability accordingly. At non-owned manufactured gas plant sites, the Company may bear full or partial responsibility for remedial costs.

Investigations at each of the Company-owned sites are designed to: (1) determine if environmental contamination problems exist; (2) if necessary, determine the appropriate remedial actions; and (3) where appropriate, identify other parties who should bear some or all of the cost of remediation. Legal action against such other parties will be initiated where appropriate. As site investigations are completed, the Company expects to determine site-specific remedial actions and to estimate the attendant costs for restoration. However, since investigations and regulatory reviews are ongoing for most sites, the estimated cost of remedial action is subject to change.

The Company determines site liabilities through feasibility studies or engineering estimates, the Company’s estimated share of a PRP allocation, or, where no better estimate is available, the low end of a range of possible outcomes is used. Estimates of the cost of remediation and post-remedial monitoring are based upon a variety of factors, including identified or potential contaminants, location, size and use of the site, proximity to sensitive resources, status of regulatory investigation, and knowledge of activities at similarly situated sites. Actual expenditures are dependent upon the total cost of investigation and remediation and the ultimate determination of the Company’s share of responsibility for such costs, as well as the financial viability of other identified responsible parties since clean-up obligations are joint and several. It is more difficult to estimate the costs to remediate certain non-owned sites, since they primarily relate to sites that have been owned and operated by other parties and because they have not undergone site investigations.

As a consequence of site characterizations and assessments completed to date and negotiations with other PRPs or with the appropriate environmental regulatory agency, the Company has accrued a liability in the amount of $332 million which is reflected in the Company’s Consolidated Balance Sheets at September 30, 2003. The potential high end of the range is presently estimated at approximately $555 million. The reserve has been increased by $31 million since March 31, 2003 primarily due to the accrual of an additional $26 million associated with its Harbor Point site. The Company had previously filed an Article 78 petition to contest the New York Department of Environmental Conservation’s more costly remediation plan of the site. During the six-months ended September 30, 2003, the petition was denied by the court and the additional estimated costs to remediate Harbor Point were accrued.

The Merger Rate Plan provides for the continued application of deferral accounting for variations in spending from amounts provided in rates. The Company has recorded a regulatory asset representing the investigation, remediation, and monitoring obligations to be recovered from ratepayers. As a result, the Company does not believe that site investigation and remediation costs will have a material adverse effect on its results of operations or financial condition.

Legal matters:
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 court a petition for review of decisions by the New York State Public Service Commission (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 Company’s 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 the Company’s financial statements. However, AMP’s petition for review also challenges the lawfulness of the Company’s collection of exit fees from departing municipalities, regardless of the methodology used to calculate those fees. On October 27, 2003, the court dismissed the petition. AMP has 30 days from the dismissal to appeal the court’s decision.

New York State v. Niagara Mohawk Power Corp. et al.
On January 10, 2002, New York State filed a civil action against the Company and NRG Energy, Inc. in federal district court in Buffalo, New York, for alleged violations of the federal Clean Air Act and related state environmental laws at the Dunkirk and Huntley power plants, which the Company sold in 1999 to affiliates of NRG Energy, Inc. (collectively, “NRG”). The state alleged, among other things, that between 1982 and 1999, the Company modified the two plants 55 times without obtaining proper preconstruction permits and implementing proper pollution equipment controls. The state sought, among other relief, statutory penalties under the Clean Air Act, which could have a maximum value of $25,000 to $27,500 per day per violation.

The Company and NRG moved to dismiss the complaint on statute of limitations and other grounds in 2002, and on March 27, 2003, the court granted the motions in part, holding that the violations of the Clean Air Act prior to November 1996 were barred by the federal five-year statute of limitations, and that related state statutory violations prior to November 1999 were barred by the state three-year statute of limitations. This eliminated the Company’s potential exposure to statutory daily penalties prior to these dates. At the same time, the court preserved the state’s non-regulatory claims against the Company and dismissed NRG from the suit.

On April 25, 2003, the state filed a motion for leave to amend the complaint to assert new claims against both the Company and NRG for unspecified amounts. Among other things, the state is seeking to reassert daily violations of the Clean Air Act going back to 1982, the time period covered by its original complaint. On May 30, 2003, the Company filed papers in opposition to the state’s petition. Oral argument was held on July 2, 2003 and the parties are awaiting the court’s decision.

Prior to the commencement of the enforcement action, on July 13, 2001, the Company filed a declaratory judgment action in New York State court in Syracuse against NRG seeking a ruling that NRG is responsible for the costs of pollution controls and mitigation that might result from the state’s enforcement action. As a result of NRG’s voluntary bankruptcy petition, filed in New York federal bankruptcy court on May 14, 2003, the Company’s declaratory judgment action is stayed. The Company cannot predict the outcome of this litigation.

Niagara Mohawk Power Corp. v. Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C.
The Company is engaged in collections litigation to recover bills for station service rendered to the owners of three power plants (the “Plants”), which the Company sold in 1999 to three affiliates of NRG Energy, Inc.: Huntley Power L.L.C., Dunkirk Power L.L.C. and  Oswego Harbor, L.L.C (collectively, the “Defendants”).  After suit was filed, the parties agreed to stay the litigation to permit the Federal Energy Regulatory Commission (“FERC”) to try to resolve the dispute. The matter is pending before an administrative law judge.
 
NRG Energy, Inc. and the Defendants filed voluntary bankruptcy petitions in federal bankruptcy court in New York on May 14, 2003.  According to the Company’s records, the Defendants owed the Company approximately $35 million as of the date of the bankruptcy filing.  The court approved relief from the automatic bankruptcy stay, permitting the litigation before FERC to proceed.  The FERC proceeding will address the Company’s ability to charge for, and the Defendants’ obligation to pay for, station service electricity.

The Defendants have filed a Plan of Reorganization which provides pre-petition claims will not be impaired. The Company filed a claim for all pre-petition unpaid amounts. The Defendants have an opportunity to dispute the filed claims.

Note D – Segment Information

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

Note F – Subsequent Events

In July 2003, National Grid USA announced an upcoming voluntary early retirement offer (“VERO”) to eligible non-union employees in New York and New England who work in areas where workforce reductions are targeted, including transmission, retail operations (in New England), and corporate administrative functions such as finance, human resources, legal, and information technology. Eligible employees included non-union employees in the targeted functions who will be age 55 with at least ten years of service by December 31, 2004. National Grid USA sets the actual retirement dates for individuals based on business operational needs. Retirement dates will conclude no later than November 1, 2004 for the majority of enrollees, but in some cases retirements may not occur until as late as November 1, 2007. The enrollment period for the VERO ended on October 31, 2003. The Company will expense approximately $25 million of VERO costs in its fiscal quarter ending December 31, 2003.

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 municiplization and exit fees, which may have a substantial adverse impact on revenues or on the value of the Company’s assets;

(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 and reported earnings;

(f) timing and adequacy of rate relief;

(g) adverse changes in electric load;

(h) climatic changes or unexpected changes in weather patterns; and

(i) failure to recover costs currently deferred under the provisions 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”).

In July 2003, National Grid USA announced an upcoming voluntary early retirement offer (“VERO”) to eligible non-union employees in New York and New England who work in areas where workforce reductions are targeted, including transmission, retail operations (in New England), and corporate administrative functions such as finance, human resources, legal, and information technology. Eligible employees included non-union employees in the targeted functions who will be age 55 with at least ten years of service by December 31, 2004. National Grid USA sets the actual retirement dates for individuals based on business operational needs. Retirement dates will conclude no later than November 1, 2004 for the majority of enrollees, but in some cases retirements may not occur until as late as November 1, 2007. The enrollment period for the VERO ended on October 31, 2003. The Company will expense approximately $25 million of VERO costs in its fiscal quarter ending December 31, 2003.

Regulatory Agreements and the Restructuring of the Regulated Electric Utility Business

For a discussion of the Merger Rate Plan, see the Company’s Form 10-K for the fiscal year ended March 31, 2003, 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.”

Retail Bypass Exit Fees: 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 bypassing 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. A number of communities served by the Company are considering municipalizing power delivery and have requested an estimate of their exit fees.

On September 22, 2002, a retail bypass issue was presented by a New York Independent System Operator (“NYISO”) filing with FERC to implement a new station service rate. The NYISO filing 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 November 22, 2002, FERC issued an order accepting the NYISO’s station service filing, over the Company’s protest. On July 10, 2003, the Company filed modifications to its standby service rates with the PSC. If approved, these modifications would unbundle the transmission service component provided under the NYISO tariff but would continue the Company’s own retail distribution charges to these customers. The PSC has not acted on the filing.

In addition, a number of generators have complained or withheld payments associated with the Company’s delivery of station service to their generation facilities. Cases related to these disputes are pending before FERC and the state courts, and the Company cannot predict the outcome of these cases. Any lost revenue attributable to the modification or elimination of the exit fee under the Company’s retail tariff, or attributable to retail bypass, is recoverable under the Merger Rate Plan provided that the lost revenue in combination with certain other lost revenue exceeds $2 million per year.

FERC Proceedings: The FERC is contemplating major changes to the regulatory structure that governs the Company’s business. Several proposals are under consideration, any of which may affect how the Company does business. The Company cannot predict which or how many of the proposals the FERC will adopt or in what form, or whether they will have a material impact on the Company’s financial position or results of operations.

Generator Interconnections:  On July 24, 2003, FERC issued final rules seeking to standardize the procedures and contractual arrangements for new generators with capacities over 20MW to interconnect to the transmission grid.  The final rules became effective October 20, 2003, but due to the complexity of coordinating roles and responsibilities in regions with Regional Transmission Organizations (“RTOs” and Independent System Operators (“ISOs”), FERC has extended the deadline for compliance filing by RTOs, ISOs and individual transmission owners in those regions until January 20, 2004. The Company sought rehearing of various aspects of these rules which could have materially adverse impacts on the Company, and it is actively working in the regional stakeholder process to implement the rules in a manner that will mitigate such adverse impacts.  In particular, the rules appear to require the implementation of pro forma agreements for generator interconnections without recognizing the Company’s rights under the Federal Power Act to set the rates, terms and conditions of access to its transmission facilities, and without clearly delineating the rights and obligations of the Company relative to an ISO or RTO and relative to neighboring control areas that might be affected by the interconnection.  In addition, FERC issued a formal notice of proposed rulemaking (“NOPR”) for special rules governing the interconnection of generators with capacities under 20MW.

Regional Transmission Organizations: On September 16, 2003, FERC issued an order terminating its proceeding on the NYISO’s filing of several years ago to become an RTO. FERC had previously rejected that filing on several grounds, and a rehearing request by the New York transmission owners, including the Company, was pending for some time. On October 23, 2003, the transmission owners filed a petition for rehearing of FERC’s September 16, 2003 order because it terminated the proceeding without addressing the transmission owners’ pending rehearing petition. The transmission owners are taking this action due to concern that the prior adverse order, if left unchallenged, could be damaging precedent. Although discussions are ongoing in New York on whether and how to change the governance structure of the NYISO to better align with FERC’s requirements for RTOs (including the requirement that the market operator be independent from the market), there are currently no formal efforts underway in New York to establish an RTO.

Standard Market Design: In July 2002, the FERC issued a NOPR on standard market design (“SMD”). The proposed rules address transmission pricing and planning, the role of merchant transmission, and other issues that would directly affect the Company. The FERC issued a White Paper on April 28, 2003 outlining a proposed wholesale power market platform that it would require in any final rules in this proceeding. The White Paper embodies FERC’s response to the comments that it received in this proceeding. FERC states that it intends to issue a rule requiring that every public utility join an independent entity (either an RTO or an ISO) that would be responsible for transmission service, tariff design, system operations, and markets within a region. States would have a significant role in regional transmission planning, tariff design, and ensuring resource adequacy. Transmission owners that are market participants would have limited authority to manage transmission. Independent transmission companies may manage a broader set of functions. To the extent the Company wishes to pursue opportunities related to transmission projects, the FERC rulings in the SMD proceeding and other proceedings may limit the Company’s ability to do so.

Standards of Conduct: In September 2001, the FERC initiated a NOPR regarding affiliate standards of conduct in both the electric and gas industries. In its proposed rules, the FERC proposed a broad definition of "energy affiliate," which would include the Company’s affiliate National Grid USA Service Company, Inc., as well as the Company’s electric distribution company affiliates. If the FERC were to adopt these rules as proposed, the Company would have to change the way it interacts with its so-called energy affiliates in a manner that could increase costs.

Incentive Pricing: In January 2003, the FERC proposed a pricing policy statement indicating that it may provide incentives to transmission owners to join an RTO or an independent transmission company and to invest in new facilities. The FERC has solicited comments on this statement, and the Company cannot predict what the final policy statement will say or whether it will have a material impact on the Company’s financial position or results of operations.

Certain critical accounting policies are based on assumption and conditions that, if changed, could have a material effect on the financial condition, results of operations and liquidity of the Company. See the Company’s Annual Report on Form 10-K for the period ended March 31, 2003, Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Critical Accounting Policies” for a detailed discussion of these policies.

(See the Company’s Annual Report on Form 10-K for the period ended March 31, 2003, Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Financial Position, Liquidity and Capital Resources”.)

Short Term Liquidity. At September 30, 2003, the Company’s principal sources of liquidity included cash and cash equivalents of $21 million and accounts receivable of $476 million. The Company has a negative working capital balance of $676 million, primarily due to short-term debt due to affiliates of $673 million. Ordinarily, construction-related short-term borrowings are refunded with long-term securities on a periodic basis. This approach generally results in a working capital deficit. Working capital deficits may also be a result of the seasonal nature of the Company’s operations as well as the timing of differences between the collection of customer receivables and the payments of purchased power costs. The Company believes that it will be able to meet its working capital needs through a combination of parent company equity infusions, long and short-term inter-company borrowings as well as cash flows generated from operations. The resources of the Company’s affiliates are sufficient to meet the equity and debt financing requirements of the Company. 

At September 30, 2003, the Company had short-term debt outstanding of approximately $673 million from the inter-company money pool. The Company has regulatory approval to issue up to $1.0 billion of short-term debt. National Grid USA and certain subsidiaries, including the Company, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies that invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice.

The Company had established a single-purpose, financing subsidiary, NM Receivables LLC (“NMR”), whose business consists of the purchase and resale of an undivided interest in a designated pool of the Company’s customer receivables. On August 6, 2003 the Company terminated NMR’s securitization agreement with an unrelated third-party. The Company no longer believes this financing arrangement is necessary due to the additional liquidity provided by the National Grid USA money pool.

Net cash used by operating activities was approximately $4 million for the Company in the six months ended September 30, 2003. The primary reason for the negative operating cash flow was the funding of pension and post-retirement benefits.

The Company’s net cash used in investing activities increased by approximately $312 million in the six months ended September 30, 2003 as compared to the same period in the prior year. This increase was primarily due to $250 million of cash received last year in connection with a November 2002 nuclear station sale, and a $55 increase in capital expenditures from the prior year.

The Company’s net cash provided by financing activities increased by approximately $601 million in the six months ended September 30, 2003 as compared to the same period in the prior year, primarily due to an equity contribution of $309 million in the current period from the Company’s parent company and a dividend paid to its parent company in the prior period of $150 million. Reductions in long-term debt were funded through long-term and short-term intercompany borrowings. The $309 million equity contribution was used to fund contributions to the pension and post-retirement trusts.

As noted in the Company’s Annual Report on Form 10-K for the fiscal year ended March 31, 2003, in connection with an audit performed by the New York Public Service Commission Staff (“Staff”), the Company reached a settlement with the Staff that resolves all issues associated with its pension and other postretirement benefit obligations for the period prior to the acquisition of the Company by National Grid. (For a more detailed discussion, see the Company’s Form 10-K, Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “PSC Issues”.) The settlement was approved by the full New York State Public Service Commission in July 2003.

During the three-months ended September 30, 2003, the Company made an open market purchase of 610,000 shares of its Series D Preferred Stock for approximately $31 million.

Long-Term Liquidity. The Company’s total capital requirements consist of amounts for its construction program, working capital needs, and maturing debt issues. See the Company’s Annual Report on Form 10-K for the fiscal year ended March 31, 2003, Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Financial Position, Liquidity and Capital Resources” for further information on long-term commitments.

Earnings

Net income for the three months ended September 30, 2003 increased by approximately $19 million compared to the three months ended September 30, 2002. This increase is primarily due to decreased other operation and maintenance expense and decreased interest expense. These items were offset by decreased total operating revenues resulting from milder weather and increased income tax expense.

Net income for the six months ended September 30, 2003 decreased by approximately $5 million compared to the six months ended September 30, 2002. This decrease is primarily due to decreased total operating revenues resulting from milder weather and increased income tax expense. These items were offset by decreased other operation and maintenance expense and decreased interest expense.

Revenues

Electric revenues decreased $20 and $41 million in the three and six months ended September 30, 2003, respectively, as compared to the comparable periods in the prior year. The table below details components of this fluctuation.

The decrease in retail sales for the three and six months ended September 30, 2003 was primarily attributable to a decrease in electric kilowatt-hour (“KWh”) deliveries to 8.8 billion and 16.8 from 9.3 and 17.4 billion, respectively, in the comparable periods in the prior year. The KWh decrease is primarily due to milder weather this year versus last year, particularly in the months of June, July and August. The effects of weather account for 80% and 85% of the decline in KWh sales for the quarter and six months, respectively. Prior period adjustments relating to revenue collected for gross earnings tax and the recording of a $3 million prior period refund to customers also decreased retail sales revenues. These decreases were partially offset by the effects of an increase in the average cost of purchased electric energy during the period which the Company is allowed to reconcile through its commodity adjustment clause.

The decrease in transmission revenue reflects certain pre-merger revenues that were recorded in the first half of fiscal 2003, that were later reversed and recorded to goodwill in the third fiscal quarter of that year.

Gas revenues increased $7 million and $55 million in the three and six months periods ended September 30, 2003, respectively, from the comparable periods in the prior year. These increases are primarily a result of higher gas prices being passed through to customers. The table below details components of this fluctuation.

The volume of gas sold for the three and six months ended September 30, 2003, excluding transportation of customer-owned gas, increased approximately 30 thousand Dekatherms (“Dth”) and decreased 464 thousand Dth, or a 1 percent increase and 3 percent decrease, respectively, from the comparable periods in the prior year.

Operating Expenses

Electricity purchased increased $2 million and $4 million for the three and six months ended September 30, 2003, respectively, as compared to the comparable periods in the prior year. Although the Company purchased less KWh of electricity for the periods, this was more than offset by the increased price of electricity due to higher fuel costs.

Gas purchased expense increased $6 million and $57 million for the three months and six months ended September 30, 2003, respectively, as compared to the comparable periods in the prior year. This increase is primarily a result of $5 million and $59 million increases in gas prices for the three and six month periods ended June 30, 2003, respectively.

Other operation and maintenance expense decreased $36 million and $33 million for the three and six months ended September 30, 2003, respectively, as compared to the comparable periods in the prior year. These decreases were primarily due to current year reduced administrative and general expenses resulting from merger-related efficiencies and an $18 million pension settlement loss in the prior year. Also contributing to the decrease were reductions in bad debt expense of $10 million and $4 million for the three and six months ended September 30, 2003, respectively, as compared to the comparable periods in the prior year. Bad debt expense in September 2002 included a one-time adjustment of $18 million. These decreases were partially offset by costs associated with an April 2003 ice storm and other miscellaneous costs.

Amortization of stranded costs increased $8 million and $16 million for the three and six months ended September 30, 2003, respectively, as compared to the comparable periods in the prior year in accordance with the Merger Rate Plan. Under the Merger Rate Plan, which began on January 1, 2002, the stranded investment balance per the Merger Rate plan is being amortized unevenly at levels that increase during the term of the ten-year plan that ends December 31, 2011.

Other taxes decreased $4 million and $13 million for the three and six months ended September 30, 2003, respectively, as compared to the comparable period in the prior year. These decreases are primarily due to a reduction of Gross Receipts Tax (“GRT”) rates which resulted in decreased GRT of $6 million and $18 million for the three and six months ended September 30, 2003, respectively, as compared to the comparable period in the prior year, and decreased sales tax. Partially offsetting these decreases were increased property taxes of $5 million and $8 million for the three and six months ended September 30, 2003.

Income taxes increased $14 million and $16 million for the three and six months ended September 30, 2003, respectively, as compared to the comparable periods in the prior year primarily due to higher book taxable income. Also, in the six months ended September 30, 2003 there was a $9 million adjustment to taxes which increased income tax expense.

Interest charges decreased $22 million and $29 million for the three and six months ended September 30, 2003, respectively, as compared to the comparable periods in the prior year, primarily due to the repayment of third-party debt using affiliated company debt at lower interest rates.

Item 3. Quantitative and Qualitative Disclosure About Market Risk

There were no material changes in the Company’s market risk or market risk strategies during the six months ended September 30, 2003. For a detail discussion of market risk, see the Company’s Annual Report on Form 10-K for fiscal year ended March 31, 2003, Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

The Company maintains disclosure controls and procedures which are designed to provide reasonable assurance that material information relating to the Company, including its consolidated subsidiaries, is made known to management by others within those entities, particularly during the period in which this report is being prepared. The Company maintains a Disclosure Committee, which is made up of several key management employees and which reports directly to the Chief Financial Officer and Chief Executive Officer. The Disclosure Committee monitors and evaluates these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, it was determined that these disclosure controls and procedures were effective in providing reasonable assurance during the period covered in this report. There were no significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of the most recent evaluation.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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 court a petition for review of decisions by the New York State Public Service Commission (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 Company’s 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 the Company’s financial statements. However, AMP’s petition for review also challenges the lawfulness of the Company’s collection of exit fees from departing municipalities, regardless of the methodology used to calculate those fees. On October 27, 2003 the court dismissed the petition. AMP has 30 days from the dismissal to appeal the court’s decision.

For a discussion of other pending legal proceedings, see Note C, Contingencies, in Part I, Item 1. Notes to Unaudited Consolidated Financial Statements.

In lieu of an Annual Meeting of Stockholders, Niagara Mohawk Holdings, Inc., the sole holder of the Company’s common stock, which is the only stock with general voting rights, took the following actions by written consent as of July 11, 2003:

On August 14, a massive power outage occurred in the Northeast U.S. and parts of eastern Canada, which affected a portion of the Company’s service territory. The Company was able to restore its electric load fully within 23 hours after the blackout began. A joint U.S.-Canadian task force is investigating the blackout to determine the root cause or causes. The Company cannot predict the outcome of the investigation nor can it predict the impact of any resulting recommendations for the operation of the transmission grid on its business or results of operations.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report on Form 10-Q for the quarter ended September 30, 2003 to be signed on its behalf by the undersigned thereunto duly authorized.