                                                                                          October 21, 2005

BY EDGAR

Mr. Robert Babula
Staff Accountant
Division of Corporation Finance
U.S. Securities and Exchange Commission
100 F Street, N.E.
Washington, D.C. 20549

      Re:    Niagara Mohawk Power Corporation
                Form 10-K for the fiscal year ended March 31, 2005 and
                Form 10-Q for the quarter ended June 30, 2005 (File No. 001-2987)

Dear Mr. Babula:

By letter dated September 28, 2005 (the "Comment Letter"), the staff (the "Staff") of the U.S. Securities and Exchange Commission (the "Commission") provided certain comments on the Annual Report on Form 10-K for the fiscal year ended March 31, 2005 and the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2005 (both File No. 001-2987) filed by Niagara Mohawk Power Corporation (the "Company") with the Commission on June 29, 2005 and August 12, 2005, respectively. This letter contains the Company's responses to those comments.

For convenience, we have reproduced the Staff's comments below in boldfaced italics and provided responses immediately below them.

Capitalized terms used in this letter and not otherwise defined have the meanings ascribed to them in the Form 10-K.

Form 10-K for the fiscal year ended March 31, 2005

Quantitative and Qualitative Disclosures about Market Risk, page 21

Gas Supply Price Risk, page 24

The date in the disclosure is correct and the number of contracts for each period is in fact relevant. Prospectively, we will disclose the number of open contracts at the end of the current and prior fiscal years. As of March 31, 2005, there were 593 open futures contracts.

Consolidated Statements of Comprehensive Income, page 27

2. Prospectively, separately report the amount of gains and losses reclassified out of accumulated other comprehensive income into earnings for the period related to your hedging activity. See paragraph 47 of SFAS no. 133. In this regard, it appears that "hedging activity" represents the net addition to OCI. If our understanding is incorrect, please clarify it.

We note the Staff's observation that the reported hedging activity represents the net addition to OCI for the period. Prospectively, we will separately report the amount of gains and losses reclassified out of accumulated other comprehensive income into earnings for the period relating to the hedging activity.

4. Regulatory assets are very significant to your balance sheet. Prospectively, please ensure that you adhere to the disclosure requirements of paragraph 20 of SFAS no. 71. If recovery of your regulatory assets is provided without a return, or a return not characteristic of the cost of capital, you should disclose the amounts of such assets and the remaining recovery period applicable to them.

SFAS no. 71, paragraph 20, requires disclosure of the remaining amounts and recovery periods of regulatory assets which are being recovered outside of rate base without a return on investment. Rate base represents cash expenditures for plant facilities and other cash based deferred assets required in supplying utility service to customers. Regulatory assets are either deferrals of cash outlays or offsets to accrued liabilities (that is, non-cash based regulatory assets). Paragraph 20 applies only to cash based regulatory assets. All of our cash based regulatory assets earn a rate of return characteristic of the cost of capital or are a component of our utility rate base. For this reason, we have made no disclosure pursuant to paragraph 20.

Note D - Commitments and Contingencies, page 39

Legal Matters - Retail Bypass, page 41

5. Please quantify for us the amount of payments withheld to date regarding your station service delivery charges, and how you have accounted for such amounts withheld in light of the FERC decision. Furthermore, please quantify for us the amount of distribution charges you have recorded in the past two years that would be considered at risk of non-collection. A description of station service charges and an example of how such charges are calculated would be helpful to the staff's understanding.

Station service is the delivery of energy to a wholesale generator when the generator cannot self-supply. The generators are charged the applicable retail rate which in most cases is the Service Class-7 rate approved by the New York Public Service Commission (PSC). Under Federal Energy Regulatory Commission (FERC) orders, these customers are generally authorized to bypass this retail rate and to receive service directly from the New York Independent System Operator under a transmission rate that significantly reduces or eliminates all station service delivery revenues to the Company.

As of March 31, 2005, the cumulative amount of station service delivery charges associated with the bypass and withheld by generators was approximately $43 million, of which $17 million was billed during the past two fiscal years. These charges were recorded to accounts receivable (A/R) with an equal and offsetting credit to revenues. As a result of the most recent FERC decisions, the Company reclassified the A/R to regulatory assets (by debiting regulatory assets and crediting A/R). This reclassification to regulatory assets reflects our view that the Company is allowed to recover these amounts from other retail customers under the Company's Merger Rate Plan and standby rate settlement. As explained in the response to comment 12, on July 29, 2005 the Company filed a proposal to recover a portion of these deferrals and that recovery is subject to PSC review and approval.

6. Prospectively, enhance your long-term debt table to include the month that your bonds will mature. Please also disclose any call or sinking fund terms or indicate which bonds are non-callable. See Rule 5-02 of Regulations S-X as well as paragraph 4 to SFAS no. 129. Tell us why you have not refinanced your higher rate debt given current prevailing interest rates if such debt was callable.

We have either refinanced or redeemed debt when financially beneficial to do so, and when callable under the debt's terms and conditions. From January 2002 through March 2005, $911 million of higher-rate debt was redeemed. Note E contains further detail on our long-term debt. We continue to monitor the potential benefits and costs of refinancing or redeeming existing debt. Accordingly, our long-term debt on our balance sheet is either non-callable or would not be economically feasible to call.

7. Please explain to us why you are using different expected returns on plan assets for your postretirement benefit plan other than pension (PBOP), and your pension benefits. We note the difference in the distribution of investment assets by type of plan. If this is the reason for the difference, explain to us how you determined your expected return on plan assets for each benefit plan.

We use identical capital market assumptions for the PBOP and pension plan assets. However, as indicated in the question, the underlying asset allocations and classes differ, resulting in different expected returns on assets (ROAs) and ROA assumptions for each plan. In addition, the assets of the nonunion PBOP plan are subject, in part, to income taxes which also affects the PBOP return.

We apply the capital market assumption for each underlying asset class to the asset class allocation at March 31^st to derive the overall ROA assumptions. The expected returns are then adjusted to reflect the additional return anticipated from market rebalancing and the active management of plan assets.

The capital market assumption for fixed income securities is based on current yield to maturity. The capital market assumption for equities is based on a number of factors including the expected growth rate of earnings, current dividend yields and historical data.

Medicare Act of 2003, page 58

8. Tell us the method and length of time over which you are amortizing the gain associated with the adoption of FSP 106-2. In this regard, explain how you determine the average remaining service period of active participants and correlate that period to the reduction in pension expense relative to the decrease in the benefit obligation.

Our method of accounting, including the length of amortization of the gain associated with the adoption of FSP 106-2, is governed by the PSC's "Statement of Policy Concerning the Accounting and Ratemaking Treatment for Pensions and Postretirement Benefits Other than Pensions" (SOP). Under the SOP, we are allowed to recover all normal ongoing costs associated with our pension and PBOP plans. The SOP also dictates the accounting policy for these plans. As it relates to FSP 106-2, the SOP requires that "All companies are to recognize, as part of their SFAS no. 106 expense calculation, all gains or losses described in Paragraph 56 of SFAS no. 106, except those not yet reflected in the market-related value of plan assets (if the company uses that method to value plan assets), over a 10-year period calculated on a vintage year basis." Accordingly, we are amortizing the gain associated with the adoption of FSP 106-2 over a 10-year period instead of over the average remaining service period of active participants. (We note that "vintage year" refers to the year in which SFAS no.106 gains or losses originated.)

Note J - Segments, page 59

The general information requirement of SFAS no. 131, paragraph 26, requires disclosure of the factors used to identify the enterprise's reportable segments, including its basis of organization. Consistent with this general information requirement, the Company disclosed that it is engaged principally in the business of the purchase, transmission and distribution of electricity and the purchase, distribution, sales and transportation of natural gas in New York State. The segments disclosed are gas, electricity-transmission and electricity-distribution.

Paragraphs 27 and 28 require disclosure of a measure of profit and loss and total assets for each segment. Additional disclosure is required to include other measures reviewed by the chief decision maker. Consistent with these requirements, we disclosed any applicable measures listed in the standard and certain other measures which are reviewed by the chief decision maker. These measurements include operating revenue, operating income before taxes, depreciation and amortization expense, amortization of stranded costs and total assets for each segment.

Item 14. Principal Accountant Fees and Services, page 70

Audit fees went down from fiscal 2004 to fiscal 2005 because the fees were unusually high in fiscal 2004. The primary reason for the higher level of audit fees in fiscal 2004 relates to costs associated with the Company's Form 10-KT/A filing on April 15, 2003. Such fees were incremental to the annual audit fee.

Schedule II - Valuation and Qualifying Accounts and Reserves. page 73

Prior to the Company's acquisition by National Grid, the PSC excluded from the rate base certain capital improvements at our Buffalo, New York facility. We continued to include the cost of these capital improvements on the balance sheet in utility plant with an offsetting reserve. In fiscal year 2005, the Company sold that facility, resulting in a write-off of the reserve for the aforementioned capital improvements.

Form 10-Q for the quarter ended June 30, 2005

Management's Discussion and Analysis of Financial Condition and Results of Operations, page 15

12. Please explain to us if you were granted regulatory approval to record the regulatory asset and related revenue associated with accounts receivable that were previously fully reserved. If not granted regulatory approval please tell us the entries that were made and explain your reasoning for recording as revenue.

Our rate plans allow deferral of the economic effects associated with any change in federal or state rates, laws or regulations and recovery of the effects of reclassification of costs or revenues from state to federal jurisdiction (we reference Section 2.6.1 of our previous rate plan, Power Choice, and Sections 1.2.3.5 and 1.2.4.3 of our Merger Rate Plan). Deferral is allowed if the change, evaluated individually, increases or decreases the Company's costs or revenues from regulated electric operations at an annual rate of more than $2 million per year. The Company regards the FERC decisions concerning station service as a change in regulation or reclassification of costs or revenues that would be governed under those sections of the Merger Rate Plan and, therefore, are eligible for recovery. As a consequence, we reclassified the NRG Energy, Inc. (NRG) accounts receivable balance of $35 million to regulatory assets (by debiting regulatory assets and crediting accounts receivable). We also reversed a $32 million reserve the Company had previously recorded against this receivable in connection with NRG's voluntary bankruptcy petition filed on May 14, 2003. The reserve was reversed with an offset to electric revenues (by debiting other current liabilities and crediting operating revenues-electric). The $35 million due from NRG is included in the $43 million of station service accounts receivables referred to in our response to question 5 above.

In accordance with the Merger Rate Plan, we established deferral accounts to track changes in specified costs and revenue items that have occurred since the plan was established. On July 29, 2005, the Company submitted a proposal to the Staff of the PSC to recover a portion of these deferrals. The regulatory asset related to NRG is included in the Company's deferral recovery proposal made July 29, which is subject to regulatory review and approval by the PSC.

In addition to the foregoing comments, the Staff's comment letter sought a statement regarding the following matters. The Company acknowledges that (i) it is responsible for the adequacy and accuracy of the disclosure in the filing; (ii) the Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and (iii) the Company may not assert Staff comments as a defense in any proceeding initiated by the SEC or any person under the federal securities laws of the United States.

If you have any questions or require additional information regarding our responses, please direct them to me at 508-389-2000 or by fax at 508-389-2605 or to Paul Bailey, Controller, at 508-389-2000 or by fax at 508-389-2925.

Other Property and Investments (in millions)
Non-qualified benefit trusts	$29
Non-utility property - land	17
Cash value of life insurance policies	9
Total Other Property and Investment	$55