For the transition period from __________ to __________

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q - For the Quarter Ended December 31, 2004

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

Notes to Unaudited Condensed Consolidated 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 financial position and results of operations for the interim periods presented. The March 31, 2004 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, 2004. As such, the March 31, 2004 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, 2004.

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 period ended December 31, 2004 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.

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 in the United States of America (GAAP), including the accounting principles for rate-regulated entities with respect to its regulated operations. 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 and revenues which would otherwise be charged to expense or revenues, 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 $4.9 billion and $5.2 billion at December 31, 2004 and March 31, 2004, respectively. These regulatory assets are probable of recovery under the Company's Merger Rate Plan and Gas Multi-Year Rate and Restructuring Agreement. The Company believes that the regulated cash flows to be derived from prices it will charge for electric service in the future, including the Competitive Transition Charges (CTCs), and assuming no unforeseen reduction in demand or bypass of the CTC or exit fees, will be sufficient to recover the Merger Rate Plan stranded regulatory assets over the planned amortization period with a return. Under the Merger Rate Plan, the Company's remaining electric business (electricity transmission and distribution business) continues to be rate-regulated on a cost-of-service basis and, accordingly, the Company continues to apply FAS 71 to these businesses. Also, the Company's Independent Power Producer (IPP) contracts, and the Purchase Power Agreements (PPAs) entered into in connection with the generation divestiture, continue to be the obligations of the regulated business.

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

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

NOTE C - COMMITMENTS AND 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 approximately 100 sites with which it may be associated, including approximately 50 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 (PRP). 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, 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 of $308 million and $309 million which is reflected in the Company's Condensed Consolidated Balance Sheets at December 31, 2004 and March 31, 2004, respectively. The potential high end of the range is presently estimated at approximately $535 million. The total net reserve has decreased by $1 million since March 31, 2004 primarily due to $17 million in regular spending offset by an additional $9 million accrual for anticipated remediation costs and an additional $7 million accrual for soil removal associated with manufactured gas plant 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, financial condition or cash flows.

Market Pricing: The U.S. Court of Appeals for the District of Columbia Circuit rendered a decision on March 16, 2004 finding that FERC failed to explain its rationale supporting its decision to approve a NYISO action invoking its authority through its "Temporary Extraordinary Procedures" to lower prices retroactively in the New York electricity market, based on NYISO's determination that a market design flaw existed that had caused unusually high prices in that market on two days in May 2000. The court remanded to FERC for further explanation of its decision to uphold NYISO's actions. If the FERC determines on remand that the prices should not have been adjusted by NYISO, New York State transmission owners, including the Company, would face additional expense due to the reinstatement of the higher market prices. The remand to FERC is pending and the Company cannot predict the outcome of this proceeding.

Legal matters:
FERC Refund Order. Niagara Mohawk made filings with the FERC in 2001 and 2002 reporting on the amounts of refunds that were due to certain customers in compliance with prior FERC orders. A group consisting of many of Niagara Mohawk's largest commercial and industrial customers (the Multiple Intervenors) had intervened in the cases and challenged the refund reports. On December 21, 2004, the Company reached a settlement with the Multiple Intervenors under which it will refund $1.15 million, subject to approval by the FERC.

Niagara Mohawk Power Corp. v. Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C. The Company previously owned three power plants (the Plants), which it sold to three affiliates of NRG Energy, Inc. in 1999: Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C. (collectively, the NRG Affiliates). The Company is involved in several proceedings with the NRG Affiliates to recover bills for station service rendered to the Plants. The most significant is the proceeding at FERC involving Niagara Mohawk's complaint against the NRG Affiliates for failure to pay station service charges the Company assessed under its state-approved retail tariffs. The other proceedings have all been stayed pending the outcome of the FERC proceeding. As of December 31, 2004, the NRG Affiliates owed the Company approximately $42 million for station service. On November 19, 2004, the FERC issued an order denying Niagara Mohawk's complaint and found that the NRG Affiliates do not have to pay state-approved retail rates for station service. Niagara Mohawk has petitioned the FERC for a rehearing of its order. See the Retail Bypass discussion below for more information.

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 the Company, NRG Energy, Inc. and certain of NRG's affiliates in U.S. District Court for the Western District of New York for alleged violations of the Federal Clean Air Act, related state environmental statutes, and the common law, at the Huntley and Dunkirk power plants. Without admitting any liability, on January 11, 2005, the Company and the State asked the Court to approve a settlement of the claims filed against the Company. At the same time, the State and the NRG companies asked the Court to approve their own separate settlement.  If approved, both settlements will fully resolve all claims asserted in this litigation against all parties. The Company does not expect a material impact on the results of operation for the quarter ending March 31, 2005.

Retail Bypass: As discussed in more detail in the Company's Form 10-K for the fiscal year ended March 31, 2004, a number of generators have complained or withheld payments associated with the Company's delivery of station service to their generation facilities, arguing that they should be permitted to bypass the Company's retail charges. The FERC issued two orders on complaints filed by station service customers of the Company in December 2003, allowing two generators to net their station service electricity over a 30-day period and to avoid state-authorized charges for deliveries made over distribution facilities. A third order involving the NRG Affiliates is discussed above under the caption Niagara Mohawk Power Corp. v. Huntley Power et al. These orders directly conflict with the Company's state-approved tariffs and the orders of the PSC on station service rates. The December 2003 FERC orders, if upheld, will permit these generators to bypass the Company's state-jurisdictional station service charges for electricity, including those set forth in the filing that was approved by the PSC on November 25, 2003. The Company filed for rehearing of these orders, and the FERC denied these requests in January 2005. The Company intends to appeal the December 2003 and January 2005 orders to the U.S. Court of Appeals for the District of Columbia Circuit.

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

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

NOTE D - - SEGMENT INFORMATION

The Company's reportable segments are electric-transmission, electric-distribution, and gas. The Company is engaged principally in the business of the purchase, transmission, and distribution of electricity and the purchase, distribution, sale, and transportation of natural gas in New York State. Certain information regarding the Company's segments is set forth in the following table. General corporate expenses, property common to the various segments, and depreciation of such common property have been allocated to the segments based on labor or plant, using a percentage derived from total labor or plant 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.

The deferred tax benefit (expense) on other comprehensive income for the following periods was (in thousands of dollars):

NOTE F - EMPLOYEE BENEFITS

As discussed in the Company's Annual Report on Form 10-K for the year ended March 31, 2004, the Company provides benefits to retirees in the form of pension and other postretirement benefits. The qualified defined benefit pension plan covers substantially all employees meeting certain minimum age and service requirements. Funding for the qualified defined benefit pension plans is based on actuarially determined contributions, the maximum of which is generally the amount deductible for income tax purposes and the minimum being that required by the Employee Retirement Income Security Act of 1974, as amended. The pension plans' assets primarily consist of investments in equity and debt securities. In addition, the Company sponsors a non-qualified plan (a plan that does not meet the criteria for tax benefits) that covers officers, certain other key employees, and non-employee directors. The Company provides certain health care and life insurance benefits to retired U.S. employees and their eligible dependents. These benefits are subject to minimum age and service requirements. The health care benefits include medical coverage, dental coverage, and prescription drug coverage and are subject to certain limitations, such as deductibles and co-payments.

Benefit plans' costs charged to the Company during the three and nine months ended December 31, 2004 and 2003 included the following components:

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).

Certain critical accounting policies are based on assumptions 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, 2004, 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.

EARNINGS

Net income for the three months ended December 31, 2004 increased by approximately $24 million from the comparable period in the prior year. The increase is primarily due to decreased retiree benefit expense of $39 million relating to one-time items, lower interest costs of approximately $10 million, and other savings of $7 million due in part to merger related integration. These savings were mostly offset by a decrease in electric margin of $16 million (revenue, less the cost of purchased electricity, amortization of stranded costs and gross receipts tax), an increase in income taxes of $8 million, a decrease in gas margin of $6 million (revenue, less the cost of purchased gas and gross receipts tax), and a decrease in other income and deductions of $1 million.

Net income for the nine months ended December 31, 2004 increased by approximately $69 million from the comparable period in the prior year. The increase is primarily due to lower interest costs of approximately $39 million, decreased retiree benefit expense of $53 million relating to one-time items, reduced bad debt expense of $19 million and other savings of $7 million due in part to merger related integration. These savings were mostly offset by decreased electric margin of $11 million, an increase in income taxes of $33 million, a decrease in gas margin of $3 million and a decrease in other income and deductions of $1 million.

REVENUES

Electric revenues decreased approximately $65 million and $111 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. The table below details components of this fluctuation.

The decrease in revenue is primarily due to lower purchase power costs being recovered (see decrease in purchased electricity below) offset by higher stranded cost revenues.

Gas revenues increased by $12 million and decreased by $17 million in the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. The increase for the three months ended December 31, 2004 is primarily a result of higher gas commodity prices passed through to customers. The decrease for the nine months ended December 31, 2004 can be attributed primarily to a decrease in the cost of purchased gas due to decreased volumes of gas purchased, as a result of milder weather in fiscal 2005 compared to the prior year. The table below details components of this fluctuation.

The volume of gas sold for the three months ended December 31, 2004, excluding transportation of customer-owned gas decreased 1.320 million Dekatherms (Dth) which was a 9.0 percent decrease from the comparable period in the prior year. The decrease is a result of lower overall demand due partly to milder weather and partly to a lower number of days counted in the fiscal 2005 period, as a result of differences in the Company's meter reading schedule.

The volume of gas sold for the nine months ended December 31, 2004, excluding transportation of customer-owned gas decreased 3.087 million Dth which was a 9.7 percent decrease from the comparable period in the prior year. The decrease is a result of lower overall demand primarily due to milder weather.

OPERATING EXPENSES

Purchased electricity decreased approximately $67 million and $150 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. The volume of kWh purchased for the three and nine months ended December 31, 2004 decreased 1.9 billion kWh (23%) and 3.4 billion kWh (14%), respectively, as compared to the comparable periods in the prior year. This volume decrease was offset by a 6% and 1% increase in the price of electricity for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. These costs do not impact electric margin or net income as the Company's rate plans allow full recoverability of these costs from customers.

Purchased gas expense increased approximately $18 million and decreased approximately $11 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. Contributing to the increase of $18 million in the three months ended December 31, 2004 was an increase in gas costs of $23 million which was partially offset by a decrease in volumes purchased of $5 million. Contributing to the decrease of $11 million for the nine months ended December 31, 2004 was an $18 million decrease in volumes purchased, partially offset by an increase in gas prices of $7 million. These costs do not impact gas margin or net income as the Company's rate plans allow full recoverability of these costs from customers.

Other operation and maintenance expense decreased approximately $44 million and $78 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. The table below details components of this fluctuation.

The reduction in bad debt expense for the three and nine months ended December 31, 2004 was mainly the result of a decrease in accounts receivable and improved collection practices.

The pension settlement loss recovery of $14 million reflects the PSC July 2004 approval for the Company to recover a portion of the $30 million pension settlement loss incurred in fiscal 2003. The Company has petitioned the PSC for recovery of a $21 million pension settlement loss, of which it recorded $20 million to expense in the third quarter of fiscal 2004. In fiscal 2004, the Company recorded a $19 million loss related to the non-union employee early retirement program (VERO). These pension items were recorded to expense by the Company, without a similar adjustment in the comparison period.

As part of the Company's ongoing cost savings initiative in connection with its integration with National Grid USA, the Company completed the sale of three buildings in the current fiscal year. These sales resulted in a charge of approximately $7 million (pre-tax) to expense to reflect the Company's share of its unrecovered cost of these facilities, in accordance with the PSC's orders on these matters. Other expense for the three and nine months ended December 31, 2004 as compared to the same period in the prior year, reflects ongoing reduced costs from merger-related efficiencies.

Amortization of stranded costs increased approximately $18 million and $54 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year in accordance with the Merger Rate Plan. The stranded investment balance is being amortized unevenly over the term of the Merger Rate Plan, from January 1, 2002 to December 31, 2011, at increasing levels in later years. The increases in the amortization of stranded costs are included in the Company rate plan and does not impact net income.

Other taxes increased approximately $1 million and decreased approximately $6 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. The nine month period decrease is primarily due to a reduction in gross receipts tax (GRT) due to lower rates and reduced revenues.

Income taxes increased approximately $8 million and $33 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year, primarily due to higher recorded book income. Also, in the nine months ended December 31, 2003, there was a $9 million adjustment to taxes which increased income tax expense for which there was no comparable charge in the current period.

Interest charges decreased $10 million and $39 million for the three and nine months ended December 31, 2004, respectively, as compared to the comparable periods in the prior year. The decrease in interest charges is attributable not only to the repayment of third-party debt using affiliated company debt at lower interest rates but also the refinancing of long-term tax exempt debt from fixed to floating rates. The expiration of the Master Restructuring Agreement interest savings deferral in the second quarter of fiscal 2004 (which had been amortizing an overcollection of pre-merger interest costs) also contributed to the decrease for the period.

LIQUIDITY AND CAPITAL RESOURCES

See the Company's Annual Report on Form 10-K for the period ended March 31, 2004, Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - "Financial Position, Liquidity and Capital Resources".

Short-Term. At December 31, 2004, the Company's principal sources of liquidity included cash and cash equivalents of $7 million and accounts receivable of $538 million. The Company has a negative working capital balance of $738 million primarily due to short-term debt to affiliates of $705 million. As discussed below, the Company believes it has sufficient cash flow and borrowing capacity to fund such deficits as necessary in the near term.

Net cash provided by operating activities increased approximately $507 million for the nine months ended December 31, 2004 from the comparable period in the prior year. The primary reasons for the increase in operating cash flow are:

Net cash used in investing activities decreased by approximately $11 million for the nine months ended December 31, 2004 from the comparable period in the prior year. The decrease was primarily due to a decrease in construction additions of $39 million, attributable to more capital expenditures incurred in fiscal 2004 related to the construction of a new gas pipeline and the installation of automatic meter reading devices in the Company's service territory. This decrease is offset by an increase in restricted cash of $30 million, mainly due to margin funding for hedging activities.

National Grid USA and certain subsidiaries, including the Company, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. The Company has regulatory approval to issue up to $1 billion of short-term debt. 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. An additional $521 million of cash was used in financing activities for the nine months ended December 31, 2004 from the comparable period in the prior year. This increase is primarily due to the receipt of $700 million of proceeds from a related party note in the prior period used to fund early redemptions of higher interest rate third party debt and to reduce borrowing under the intercompany money pool. In fiscal 2004, the Company received a $309 million contribution from its parent company. There were no similar receipts in the current period. The Company reduced its short-term debt to affiliates by $263 million in the nine months ended December 31, 2004 from the comparable period in the prior year. The change in receipts is offset by a decrease in reductions in long-term debt of $741 million.

On May 27, 2004, the Company completed the refinancing of $115.7 million of tax exempt bonds, 7.2%, due 2029. The new bonds were initially issued in auction rate mode.

On December 31, 2004, the Company redeemed all outstanding Cumulative Fixed/Adjustable Rate Series D Preferred Stock for $25 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, 2004, 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.

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Interest Rate Risk: The Company's major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable rate debt. At December 31, 2004, the Company's tax exempt variable rate long-term debt had a carrying value of approximately $575 million. While the ultimate maturity dates of the underlying loan agreements range from 2013 to 2029, this debt is issued in auction rate mode. The various components that comprise this debt are currently issued for periods of 7 days, 35 days, and 90 days, and are remarketed through agents at the end of each period. The weighted average rate, including a 0.25% remarketing fee, for the quarter and the nine months ended December 31, 2004, were approximately 1.88% and 1.55%, respectively.

There were no material changes in the Company's market risk or market risk strategies during the nine months ended December 31, 2004. For a detailed discussion of market risk, see the Company's Annual Report on Form 10-K for fiscal year ended March 31, 2004, Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

The Company has carried out an evaluation under the supervision and with the participation of its management, including the Chief Financial Officer and President, of the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report.

Based on that evaluation, it was determined that these disclosure controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports that the Company files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required.

No change in internal control over financial reporting occurred during the fiscal quarter ended December 31, 2004 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

New York State v. Niagara Mohawk Power Corp. et al.: As described in the Company's 10-K for the fiscal year ended March 31, 2004, the New York State Attorney General had filed a civil action against the Company, NRG Energy, Inc. and certain of NRG's affiliates in U.S. District Court for the Western District of New York for alleged violations of the Federal Clean Air Act, related state environmental statutes, and the common law, at the Huntley and Dunkirk power plants. Without admitting any liability, on January 11, 2005, the Company and the State asked the Court to approve a settlement of the claims filed against the Company. At the same time, the State and the NRG companies asked the Court to approve their own separate settlement.  If approved, both settlements will fully resolve all claims asserted in this litigation against all parties.

ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES

(i) Redeemed at the Company's option in accordance with the terms of the Cumulative Fixed/Adjustable Rate Series D Preferred Stock.


ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

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 December 31, 2004 to be signed on its behalf by the undersigned thereunto duly authorized.