Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended June 30, 2004

             For the transition period from __________ to __________

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q - For the Quarter Ended June 30, 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 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 period ended June 30, 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.

New Accounting Standards: On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act expands Medicare, primarily by adding a prescription drug benefit for Medicare-eligibles starting in 2006. The Act provides employers currently sponsoring prescription drug programs for Medicare-eligibles with a range of options for coordinating with the new government-sponsored program to potentially reduce program cost. These options include supplementing the government program on a secondary payor basis or accepting a direct subsidy from the government to support a portion of the cost of the employer's program.

Paragraph 40 of the Financial Accounting Standards Board's (FASB) Statement of Financial Accounting Standard (SFAS) No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions requires that presently enacted changes in laws impacting employer-sponsored retiree health care programs which take effect in future periods be considered in current-period measurements for benefits expected to be provided in those future periods. Therefore, under FAS 106 guidance, measures of plan liabilities and annual expense on or after the date of enactment should reflect the effects of this Act.

Pursuant to guidance from the FASB under FSP FAS 106-2, the retiree health obligations will reflect the estimated subsidy payments expected from the federal government for the participant groups anticipated to qualify for the subsidy. Participant groups who are not expected to qualify, or have not yet been determined whether they will qualify, for the federal subsidy will not impact the retiree health obligations. If any portion of this group is subsequently determined to qualify for the subsidy, the retiree health care obligations will be adjusted at the time of that determination. The Company has chosen to apply the guidance prospectively, impacting retiree health costs effective July 1, 2004. Any gains that arise from the Act would be deferred and passed back to customers.

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 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 $5.1 billion and $5.2 billion at June 30, 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 - 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 105 sites with which it may be associated, including 58 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 $318 million and $309 million which is reflected in the Company's Condensed Consolidated Balance Sheets at June 30, 2004 and March 31, 2004, respectively. The potential high end of the range is presently estimated at approximately $548 million. The total net reserve has been increased by $9 million since March 31, 2004 primarily due to the accrual of additional anticipated remediation costs associated with a manufactured gas plant site. The increase in the total net reserve was partly offset by work completed since March 31, 2004.

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:
Alliance for Municipal Power v. New York State Public Service Commission: On February 17, 2003, the Alliance for Municipal Power (AMP) filed with the New York State Supreme Court (Albany County) a petition for review of decisions by the PSC that maintain the PSC's established policy of using average distribution rates when calculating the exit fees that may be charged to municipalities that seek to leave the 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 position or results of operations. 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 AMP's petition. AMP made a timely filing to appeal the court's decision but has not perfected its appeal.

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 three proceedings with the NRG affiliates to recover bills for station service rendered to the Plants; a collections action filed by the Company against the NRG affiliates in New York State Supreme Court in October 2000; a petition filed by the Company at the FERC in November 2002, and an Article 78 Petition filed by the NRG Affiliates in New York State Supreme Court in March 2004, challenging the state retail standby distribution tariff. The main issue in all three proceedings is whether the NRG Affiliates will be permitted to bypass the Company's state-jurisdictional retail charges for station service. The New York State Supreme Court lawsuit filed by the Company has been stayed by agreement, the parties are awaiting a decision from FERC on the Company's petition, and the parties have agreed to stay the NRG Affiliates' Article 78 petition pending appeal of a FERC decision on May 10, 2004 in another proceeding. The May 10, 2004 Order denied rehearing of objections to FERC's approval of the NYISO wholesale station service tariff, on which the NRG Affiliates are relying in part to avoid payment of the state retail distribution tariff for station service. FERC's May 10, 2004 Order, and the Company's appeal from it, are discussed below under Retail Bypass. As of June 30, 2004, the NRG Affiliates owed the Company approximately $37 million for station service. In the event it is determined that the Company may not bill the NRG Affiliates for station service under its state tariff, the Company would seek recovery under its rate plans.

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 its affiliates in U.S. District Court for the Western District of New York for alleged violations of the Federal Clean Air Act, related state environmental statutes, and the common law, at the Huntley and Dunkirk power plants. The State alleged that between 1982 and 1999, the Company modified the two plants 55 times without obtaining proper preconstruction permits and implementing proper pollution equipment controls.

On March 27, 2003, the court issued an order granting in part the Company's motion to dismiss, which had been filed in 2002. Based on applicable statutes of limitations, the court reduced the number of projects allegedly requiring preconstruction permits under the Clean Air Act from 55 to 9.

On December 31, 2003, the court granted the State's motion to amend the complaint, allowing it to assert operating permit violations against the Company and NRG. In so ruling, the court stated that monetary penalties for actions outside the statute of limitations period would still be barred. The Company answered the amended complaint on March 2, 2004, and filed a counterclaim against the State of New York in response to its common law public nuisance claim, seeking contribution for the Company's portion of any alleged harm caused by emissions from facilities that the State owns or to which it has given permits. The State has moved to dismiss the counterclaim, and oral argument was heard on July 12, 2004. Trial is scheduled for March 2006.

Niagara Mohawk Power Corporation v. NRG Energy, Inc., Huntley Power L.L.C. and Dunkirk Power L.L.C. With respect to the claims asserted in the Clean Air Act lawsuit discussed above, NRG and its Affiliates have taken the position that the Company is responsible at least in part for the costs of pollution control equipment and related fines and penalties, notwithstanding contrary language in the agreement governing the sale of the Plants to the NRG Affiliates. As a result, on July 13, 2001, the Company sued NRG and the NRG Affiliates in New York State Supreme Court (Onondaga County), seeking a declaratory ruling that under the agreement, NRG is responsible for the costs of any pollution control upgrades and mitigation, as well as post-sale fines and penalties, that may result from the Clean Air Act suit. In response, NRG filed a counterclaim and filed a motion for partial summary on its counterclaim. Hearing on NRG's motion is scheduled for August 25, 2004.

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. 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 has filed for rehearing of these orders.

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 electricity-transmission, electricity-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 were (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 plans cover 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 months ended June 30, 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 June 30, 2004 increased by approximately $37 million from the comparable period in the prior year. The increase is primarily due to lower interest costs of approximately $20 million, increased electric margin of $8 million, decreased other operations and maintenance costs of $11 million, a non-recurring cost of $6 million in the prior year (related to the April 2003 ice storm) for which there was no comparative charge in the current year, and an increase in income taxes of $11 million.

REVENUES

Electric revenues decreased approximately $25 million for the three months ended June 30, 2004 from the comparable period 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) partially offset by higher electric KWh deliveries.

Gas revenues decreased approximately $34 million for the three months ended June 30, 2004 from the comparable period in the prior year. This decrease is primarily due to lower purchased gas prices being passed to customers and, to a lesser extent, a decrease in the volume of gas sold. The table below details components of this fluctuation.

The volume of gas sold for the three months ended June 30, 2004 decreased 1.6 million Dekatherms (Dth) or a 12.3 percent decrease from the comparable period in the prior year due to milder weather in the current year.

OPERATING EXPENSES

Purchased electricity decreased approximately $51 million for the three months ended June 30, 2004 from the comparable period in the prior year. The volume of KwH sold for the three months ended June 30, 2004 decreased 1.6 billion KwH (17%) from the comparable period in the prior year. This volume decrease was offset by a 4% increase in the price of electricity. 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 decreased $33 million for the three months ended June 30, 2004 as compared to the same period in the prior year primarily as a result of a $22 million decrease in gas prices and a decrease of $11 million in the volume of gas purchased. 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 $11 million for the three months ended June 30, 2004 from the comparable period in the prior year. The table below details components of this fluctuation.

The reduction in bad debt expense was the result of improved collection practices. 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 a building in the current fiscal quarter. This sale resulted in a charge of approximately $4 million (pre-tax) to expense to reflect its share of its unrecovered cost of this facility. See "Other Regulatory Matters" below for a discussion regarding the regulatory treatment of the sale of the building. The increase in other reflects minor increases in various categories of expense, including certain costs associated with the May 1 implementation of a new enterprise resource planning and work management systems, partially offset by ongoing reduced costs from merger-related efficiencies.

Amortization of stranded costs increased approximately $18 million for the three months ended June 30, 2004 from the comparable period 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. The increases in the amortization of stranded costs is included in the Company rate plan and does not impact net income.

Other taxes decreased approximately $4 million for the three months ended June 30, 2004 from the comparable period in the prior year. This decrease is primarily due to a reduced gross receipts tax (GRT) as a result of reduced revenues and a reduction in payroll taxes caused by fewer employees due to the significant number of retirements that occurred in fiscal 2004.

Income taxes increased approximately $11 million for the three months from the comparable period in the prior year. This increase is primarily due to higher book taxable income of $20 million and a $9 million accrual to return adjustment in the prior period for which there was no comparable charge in the current period.

Interest charges decreased $19 million for the three months ended June 30, 2004 from the comparable period in the prior year. This decrease is primarily due to the repayment of third-party debt using affiliated company debt at lower interest rates. Also, 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) contributed to the decrease for the period.

(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 June 30, 2004, the Company's principal sources of liquidity included cash and cash equivalents of $51 million and accounts receivable of $508 million. The Company has a negative working capital balance of $535 million primarily due to short-term debt to affiliates of $546 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 $175 million for the three months ended June 30, 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 $33 million for the three months ended June 30, 2004 from the comparable period in the prior year. This decrease was primarily due 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.

An additional $158 million of cash was used in financing activities for the three months ended June 30, 2004 from the comparable period in the prior year. This increase is primarily due to the receipt of $350 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. There is no similar receipt in the current period. Offsetting the increase was increased short-term intercompany borrowing in the current period.

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. The original bonds were issued in 1994 to finance pollution control assets located at Nine Mile Point nuclear power station.

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.

Pension settlement loss. In February 2004, the Company reached an agreement with PSC Staff that would provide rate recovery for approximately $15 million of the $30 million pension settlement loss incurred in fiscal 2003. This agreement was approved by the full New York State Public Service Commission in July 2004. In addition, the agreement covers the funding of the entire settlement loss to benefit plan trust funds. The order became effective on August 11, 2004 and under the agreement, the Company will fund the non-recoverable portion of this loss within 30 days of receipt of the written order. The Company will record this recovery in the second quarter of the current fiscal year. In addition, the Company has recently filed a petition with the PSC seeking recovery of its fiscal year 2004 settlement losses and is unable to predict the outcome of this filing. For further discussion of the settlement losses see the Company's Annual Report on Form 10-K for the period ended March 31, 2004, Part II , Item 8. Financial Statements and Supplementary Data - Note H. Employee Benefits.

Building sale. During fiscal 2004, the PSC issued an order related to a proposed sale of a Company building. The order addresses the sharing between customers and the Company of sales proceeds and future avoided costs that will result from disposal of the building, as well as the sharing of the transaction costs and remaining net book value of this facility. In its order, the PSC has directed the Company to share with customers 50% of the benefits and costs associated with the sale, including the undepreciated net book value of the building. During the current fiscal quarter the Company completed the sale of the building and has recorded a net charge of approximately $4 million (pre-tax) to expense, reflecting its net unrecovered cost of this facility. The order also directs the Company to follow the same accounting and ratemaking treatment for the sale of other buildings during the term of the Merger Rate Plan.

Stray voltage. The PSC issued an order in July 2004 seeking comments on a proposal which, if adopted, would require all electric utilities in the state to test annually all of their publicly accessible transmission and distribution facilities for stray voltage.  The proposal also contemplates strict compliance requirements and potential financial penalties for failure to achieve testing and inspection targets.  It is not yet clear how broad in scope the inspection requirements would be, nor is it clear how the financial penalty mechanism being contemplated would be administered, if adopted.

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 three months ended June 30, 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.

During the most recent fiscal quarter, the Company completed implementation of a new enterprise resource planning and information system to integrate its finance and accounting, supply chain and work management information systems. The implementation of this new system has resulted in new processes for recording the underlying transactions of the Company's financial statements. As such, the Company's internal controls have been modified to encompass these new processes.

As reported in the Company's for 10-K for the fiscal year ended March 31, 2004, on May 4, 2004, by unanimous written consent of the sole common stockholder, the following actions were taken:

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 June 30, 2004 to be signed on its behalf by the undersigned thereunto duly authorized.