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300 ERIE BOULEVARD WEST, SYRACUSE,
NEW YORK 13202

     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

1.    You indicate that you had 453 open futures
contracts at March 31, 2004.  Please confirm the date of your disclosure is
correct.  If so, tell us why the number of contracts at March 31, 2004 was
relevant whereas at the same date in 2005 it was not
relevant.

RESPONSE:

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.

RESPONSE:

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.

Consolidated Balance Sheets, page
29

3.    Summarize for us what comprises other property
and investments totaling $55.048 million as of March 31,
2005.

RESPONSE:

Please see the table below.

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

Note B - Rate and Regulatory
Issues, page 37

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.

RESPONSE:

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.

RESPONSE:

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.

As described in our response to comment 12, we had
previously established a reserve of $32 million in connection with one station
service customer's accounts receivable balance.  We reversed this reserve
in the first quarter of fiscal
2006.

Note E - Long-Term
Debt, page 42

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.

RESPONSE:

We will enhance our long-term debt table in future filings
by disclosing the month of maturity and any call or sinking fund terms
associated with our long-term debt.

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.

Note H - Employee Benefits, page
51

Pension Benefits, page
52

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.

RESPONSE:

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 31st 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.

RESPONSE:

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

9.    Please tell us how you are complying with the
disclosure requirement of paragraphs 26-28 of SFAS no.
131.

RESPONSE:

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

10.   Explain to us why your audit fees went down by
approximately 49% from 2004 to 2005.

RESPONSE:

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

11.   Explain to us what comprised your
miscellaneous reserve and how the reserve was written
off.

RESPONSE:

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.

RESPONSE:

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