For the quarterly period ended December 31, 2003

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q - For the Quarter Ended December 31, 2003

ITEM 1. FINANCIAL STATEMENTS

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 nine-month periods ended December 31, 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 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.

New Accounting Standards: In December 2003 the Financial Accounting Standards Board revised Statement on Financial Accounting Standards No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (“FAS 132”). The revised statement retains the disclosure requirements contained in the original statement and adds new disclosures about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension and other defined benefit postretirement plans. The revised FAS 132 is effective for fiscal years ending after December 15, 2003 and for interim periods beginning thereafter, so it does not apply to the Company in the quarter ended December 31, 2003. FAS 132 does not change the measurement or recognition of the aforementioned plans and, as such, the adoption of this statement will not have any effect on the Company’s financial position, results of operations, or cash flows.

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, Statement of Financial Accounting Standards No. 71 “Accounting for the Effects of Certain Types of Regulation” (“FAS 71”) permits a public utility, regulated on a cost-of-service basis, to defer certain costs, which would otherwise be charged to expense, when authorized to do so by the regulator. These deferred costs are known as regulatory assets, which in the case of the Company, are approximately $5.2 billion at December 31, 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 FAS 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 FAS 71 and would be required to record an after-tax, non-cash charge against income for any remaining unamortized regulatory assets and liabilities. If the Company could no longer apply FAS 71, the resulting charge would be material to the Company’s reported financial condition and results of operations.

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

Stranded Costs: Under the Merger Rate Plan, a regulatory asset was established that included the costs of the Master Restructuring Agreement (“MRA”), the cost of any additional IPP contract buyouts and the deferred loss on the sale of the Company’s generation assets. The MRA represents the cost to terminate, restate or amend IPP contracts. The Company is also permitted to defer and amortize the cost of any 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 in accordance with federal, state and local environmental agency requirements to investigate and remediate, as necessary, 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 is currently aware of 111 sites with which it may be associated, including 60 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 Condensed Consolidated Balance Sheets at December 31, 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 after the State of New York Supreme Court’s denial of the Company’s Article 78 petition which had incorporated lower costs than the State’s recommended alternative as set forth in the Record of Decision.

On November 7, 2003, the New York State Department of Environmental Conservation (“DEC”) executed a new multi-site consent order with the Company. This new order supersedes the original 1992 order for the owned Manufactured Gas Plant (“MGP”) sites and provides the Company with many benefits including the ability to contest future DEC decisions and scheduling flexibility in the investigation and remediation of MGP sites.

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. In late November 2003, AMP made a timely filing 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. By order dated December 31, 2003, the court granted the state’s motion to leave to amend the complaint to assert claims against NRG and the Company based on violations of the plants’ operating permits. The court order brings NRG back into the case for injunctive relief but does not disturb the prior ruling that monetary penalties for Clean Air Act violations five years prior to the suit are barred by the statute of limitations.

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 had been stayed. The stay has now been lifted by virtue of the bankruptcy court’s confirmation of NRG’s plan of reorganization on November 24, 2003 and those of Dunkirk Power L.L.C. and Huntley L.L.C.’s on November 25, 2003. 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 with NRG Energy, Inc., “NRG”).  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.
 
NRG emerged from bankruptcy in December 2003 and the Plants did not discharge their debt.  According to the Company’s records, the Defendants owed the Company approximately $35 million as of the date of the bankruptcy filing.  

The FERC has not yet rendered a decision on this matter. However, on December 23, 2003, it issued two orders on related complaints filed by AES Somerset, L.L.C. (“AES”) and Nine Mile Point Nuclear Station, L.L.C., both of which are station service customers of the Company. The orders do not control the outcome of the NRG case but may be indicative of the FERC’s disposition in station service matters. 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 order, it is possible to construe it to have retroactive effect back to the date the plant was sold to AES by a third party. The net effect of these decisions is that the two generators will no longer have to pay the Company for station service charges for electricity. The Company is seeking rehearing on these decisions and is awaiting a decision on NRG. In the event that the FERC orders are finally upheld, the Company believes it would recover the lost revenues under its rate plans.

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 – VOLUNTARY EARLY RETIREMENT OFFER

In the quarter ended December 31, 2003, the enrollment period ended with respect to the voluntary early retirement offer (“VERO”) made by National Grid USA. The VERO was made to eligible non-union employees in New York and New England in areas including transmission, retail operations (in New England), and corporate administrative functions such as finance, human resources, legal, and information technology. The majority of employees 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 quarter ended December 31, 2003. This amount included approximately $9 million allocated to the Company from National Grid USA Service Company, an affiliate. A total of 53 employees of the Company accepted the VERO.

NOTE G – PENSION SETTLEMENT LOSSES

As a result of the decline in the stock market since the close of the merger and a reduction in the discount rate applied to pension obligations, the Company has an unrecognized loss in its pension plans. Under Statement of Financial Accounting Standards No. 88 “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” (“FAS 88”), the Company must recognize a portion of this loss immediately when payouts from the plans exceed a certain amount. Accordingly, the Company recognized a loss of $29.4 million in its fiscal year ended March 31, 2003. In February 2004, the Company reached an agreement with PSC Staff that would provide rate recovery for $14.5 million of the $29.4 million pension settlement loss. The agreement also covers the funding of the entire settlement loss to benefit plan trust funds. This agreement is subject to approval by the full New York State Public Service Commission. Under the agreement, within 30 days of approval, the Company will fund the nonrecoverable portion of this loss.

In December 2003, the Company recorded a new pension settlement loss of $20 million under FAS 88 associated with pension payouts in its fiscal year ending March 31, 2004. Additional losses may be recorded in the remaining months of the fiscal year. The Company plans to file a petition with the PSC seeking to recover these losses.

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) 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”).

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: 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. 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 different type of retail bypass issue was presented in a filing with FERC by the New York Independent System Operator (“NYISO”) seeking to implement a new station service rate. On November 22, 2002, FERC issued an order accepting the NYISO’s new rate, over the Company’s protest. The 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 tariff 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 1, Note C – 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”), 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 order, it is possible to construe it 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 FERC orders are in direct conflict with the orders of the NYPSC 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. The Company is seeking rehearing on these FERC decisions but cannot predict the outcome of these cases.

Other generators have also taken the position that they are not required to pay station service charges, on grounds similar to those alleged in the AES and Nine Mile complaints. These FERC orders have increased the risk that ISOs will be able to bypass local distribution company charges (including stranded cost recovery charges) when providing transmission level power to generating stations and, potentially, that other customers will also be able to bypass those charges when taking service at transmission voltages. The FERC orders appear to be limited to delivery service provided to generators in the context of station service, but if FERC were to extend these orders to other customers, the Company could experience a potentially significant reduction in revenue. In the event that the FERC orders are finally upheld, the Company believes it would recover the lost revenues under its rate plans.