                                                                                          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:      New England Power Company
                  Form 10-K for the fiscal year ended March 31, 2005 (File No. 001-6564)

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 (File No. 001-6564) filed by New England Power Company (the "Company") with the Commission on July 14, 2005. 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.

General

We have not presented Schedule II because we have no material reserves against accounts receivable. There is a reserve of $153,000 (less than .1% of accounts receivable) recorded against other accounts receivable which is reflected on the face of both balance sheets presented. In future filings, the balance sheets would not separately report a reserve unless it is material.

Business, page 4

Compliance with Environmental Requirements, page 6

14. You indicate that you have initiated a program to investigate and remediate certain properties which you have determined may be contaminated with industrial waste. Describe to us the properties in question and, if available, please quantify for us the estimated potential range of remediation costs. Tell us why no apparent disclosure exits in the financial statements pursuant to SFAS no. 5.

We are aware of fewer than 10 sites for which the Company has been named a potentially responsible party. As of March 31, 2005, we have reserved approximately $8 million for cleanup costs at these sites. Approximately $7 million of the reserve is for remediation of a site at which ash was disposed by fossil fuel generating plants formerly owned by the Company.

Under its settlements authorizing stranded cost recovery, NEP is allowed to recover environmental remediation costs associated with its former ownership of generation facilities, and under its transmission tariff, NEP is authorized to recover the remediation costs associated with transmission operations. Accordingly, NEP records a regulatory asset associated with these remediation costs that offsets the reserves. In any event, we do not believe that these costs are material to our financial position or results of operations. Accordingly, we do not disclose these costs as material loss contingencies under SFAS no. 5.

Legal Proceedings, page 7

As of March 31, 2005, we have recorded a receivable from the town of Norwood and a litigation reserve for this claim. We continue to pursue our claim for payment of the entire balance, including accrued interest. However, we believe it is appropriate to reserve against the probability that we will not receive settlement of the entire balance owed.

Management's Discussion and Analysis of Financial Condition and Results of Operations, page 9

Results of Operations, page 11

16. Please quantify all changes you discuss in your results of operations. For example, you state that operating revenues decreased for the year ended March 31, 2005, as a result of decreased transmission operation and maintenance expense and decreased benefit costs billed to transmission customers, partially offset by higher CTC revenues, however, you do not quantify each change.

The Company has two primary sources of revenue: transmission and stranded cost recoveries. Transmission revenues are based on a formula rate that recovers the Company's actual costs plus a return on investment. Stranded cost recovery revenues are collected through a Contract Termination Charge (CTC), which is billed to former wholesale customers of the Company in

connection with the Company's divestiture of its electricity generation investments. Consequently, our revenues consist largely of operating costs recovered from customers. During the fiscal year ended March 31, 2003, the Company also had revenues associated with its ownership interests in the Vermont Yankee Nuclear Generating Station (Vermont Yankee) and the Seabrook Nuclear Generating Station (Seabrook). Vermont Yankee and Seabrook were sold in July 2002 and November 2002, respectively.

Net income for the year ended March 31, 2005 was not significantly different from the prior year. Affecting net income during the fiscal year were one time tax adjustments of approximately $8 million that resulted from settlement of tax audits, partially offset by approximately $2 million of interest costs associated with these settlements and approximately $5 million of reduced stranded cost recoveries.

Net income for the year ended March 31, 2004 decreased approximately $3 million compared with the prior year. The reduction was due primarily to decreased mitigation incentives of approximately $2 million and reduced return on CTCs of approximately $4 million compared with the prior year. Also contributing to the decrease was approximately $2 million of reduced equity income from nuclear generation due to the sale of Vermont Yankee Nuclear Power Corporation (Vermont Yankee) in July 2002. These decreases were partially offset by increased transmission earnings of approximately $5 million during the year ended March 31, 2004 as compared to the same periods in 2003.

Operating revenue for fiscal year ended March 31, 2005 decreased approximately $6 million compared to the prior year. The decrease was due primarily to lower revenues resulting from approximately $5 million of decreased transmission operations and maintenance expenses and approximately $5 million of decreased benefit costs billed to transmission customers, partially offset by approximately $4 million of higher CTC revenues that primarily resulted from recovery of expenses associated with the Hydro Quebec transmission line agreements (HQ Contracts). See Note B "Rate and Regulatory" in Item 8. Financial Statements and Supplementary Data for further discussion on the HQ Contracts.

Operating revenue for fiscal year ended March 31, 2004 decreased approximately $54 million compared to the prior year. The primary reason for the decrease was approximately $19 million of reduced sales of power received from Vermont Yankee and Seabrook during the fiscal year. The decrease is also related to reduced CTC revenue of approximately $38 million due to fully reconciling true-up mechanisms that allow the Company to adjust revenues proportionately with correlating expenses. In addition, reduced mitigation incentives under the CTC of approximately $3 million contributed to the reduction in operating revenue. This was offset by other revenue increases of approximately $6 million.

Purchased electric energy for the fiscal year ended March 31, 2005 increased approximately $2 million compared with the same period in 2004 primarily due to increased nuclear decommissioning costs in 2005 of approximately $6 million compared with the prior year partially offset by reductions in other purchased power expense of approximately $4 million.

Purchased electric energy for the fiscal year ended March 31, 2004 decreased approximately $33 million compared with the same period in 2003. The decrease was caused by approximately $39 million of reduced ongoing payments for purchased power due primarily to the buyout of a purchased power contract in November 2002. Also contributing to the decrease was a loss of approximately $9 million from the sale of

Operation and maintenance expense for the fiscal year ended March 31, 2005 decreased approximately $2 million compared with the same period in 2004. This decrease was due primarily to a reduction in transmission operations and maintenance costs of approximately $5 million, employee benefit charges of approximately $5 million and other expense decreases of approximately $4 million, partially offset by the resumption of support payments under the HQ contracts of approximately $12 million.

Operation and maintenance expense for the fiscal year ended March 31, 2004 decreased approximately $3 million compared with the prior year. The reduction was due primarily to the inclusion of approximately $14 million of expenses from Seabrook during the fiscal year ended March 31, 2003. Seabrook was sold in November 2002. Partially offsetting the decreased expense for the fiscal year ended March 31, 2004 were increased costs of approximately $8 million due to a voluntary early retirement program provided to employees which is discussed in Note H "Employee Benefits" in Item 8. Financial Statements and Supplementary Data, and other expense increases of approximately $3 million.

Amortization of stranded costs for the fiscal year ended March 31, 2004 decreased approximately $2 million compared with the prior year. The decrease was a result of the scheduled changes in amortization in accordance with the annual CTC filings reflecting an increase in amortization of approximately $10 million along with impacts associated with not recognizing a full year of amortization of regulatory liabilities that were established in connection with the sale of Seabrook and Vermont Yankee representing a decrease of approximately $12 million.

Income taxes decreased approximately $10 million for the year ended March 31, 2005 compared with the prior year. This decrease was a result of a $6 million reduction in tax expense from prior year tax return true-ups and settlements of tax audits in addition to a decrease in taxable income. Income taxes decreased approximately $2 million for the fiscal year ended March 31, 2004 compared with fiscal 2003 primarily due to lower taxable income.

Equity in income of nuclear power companies remained relatively unchanged during the fiscal year ended March 31, 2005 compared with the same period in the prior year. It decreased approximately $3 million during the fiscal year ended March 31, 2004 compared with the same period in fiscal 2003 due to the redemption of the Company's interest in the Vermont Yankee Nuclear Power Corporation.

Other income net remained relatively unchanged during the fiscal year ended March 31, 2005 compared with the prior year. It increased approximately $2 million during the fiscal year ended March 31, 2004 compared with fiscal 2003 due to increased interest income of approximately $1 million and the sale of nonutility property of approximately $1 million.

Interest expense increased approximately $5 million for the fiscal year ended March 31, 2005 compared with the prior year primarily due to increased interest rates on the Company's variable rate long-term debt of approximately $2 million and interest charges of approximately $2 million that resulted from a tax appeal settlement.

17. You indicate in your business discussion that the Regional Transmission Organization (RTO) commenced operations effective February 1, 2005, and the company has become a Participating Transmission Owner (PTO). Provide us an understanding of whether and how this change will affect your results of operations. If the effect related to the control of your transmission assets, please help us understand how the change will affect how you bill users of your transmission system.

Our tariff arrangements permit the Company to recover its costs and earn a return on its investment. We expect revenue and net income to increase over what they would otherwise have been in fiscal 2006, as our rates now reflect a conditional increase to return on equity, partially offset by a regulatory liability for the amount we believe may be subject to refund. That issue is currently being litigated at the Federal Energy Regulatory Commission (FERC) and in the courts and is not yet resolved. We have accounted for the interim rulings as follows. Beginning in February 2005, we incorporated a proposed return on equity of 12.8% (our then current return on equity was 10.25%) and increased our customer billing rates as authorized by the FERC. In addition, we recorded a regulatory liability in fiscal 2005 for the amount that we believe may be subject to refund to our customers. In May 2005, an administrative law judge recommended an adjusted rate of return to the FERC. As a result, we adjusted our regulatory liability in fiscal 2006 to align the potential customer refund with the judge's recommendation. The FERC is expected to issue its final order on the judge's ruling and the change to our return on equity by the end of calendar 2005. However, several parties, including the Company, have appealed prior FERC orders relating to the return on equity issue to the US Court of Appeals for the District of Columbia. Thus, a final resolution of all issues associated with the return that the Company earns retroactive to February 2005 is unlikely until 2006 or 2007.

The RTO has increased the control that the Independent System Operator -New England (ISO-NE), a public utility regulated by FERC, has over the Company's transmission assets. This increased control includes functions such as outage scheduling, capacity ratings, and administrative coordination with customers taking transmission service. The Company also has an increased obligation to build needed transmission infrastructure identified by ISO-NE. Any increased investment is recoverable under our transmission tariff.

The implementation of the RTO and our status as a PTO have not impacted how we bill users for the use of our transmission system. However, as described above, we have increased our billing rates as authorized in the FERC's February 2005 order.

Quantitative and Qualitative Disclosures About Market Risk, page 15

18. Your discussion involving the remarketing of your variable rate debt could suggest that this debt may be short-term in nature. Please provide to us an example of how the remarketing process operates. Please specifically address the consequences associated with a failed remarketing including the possibility of repurchase of the debt. Also, provide us a detailed discussion of how you concluded such debt is long-term in nature. Please reference any applicable accounting literature used to make your classification decision. Lastly, tell us whether you have hedged your interest rate exposure for any portion of your variable rate debt or whether natural hedges exist.

We have never experienced a failed remarketing. If the agents were unable to remarket the bonds, investors would have the right to "put" the bonds back to the Company. If we were required to repurchase the bonds as a result of a failed remarketing, we have lines of credit and standby bond purchase facilities that would provide the necessary liquidity. Please see "Note F - Short-term Borrowings" of the Notes to Financial Statements.

We do not hedge our interest rate exposure because we are able to remarket the bonds from time to time in fixed, auction rate and commercial paper modes. Because our debt is tax-exempt, short-term rates are generally favorable and we currently find it more cost-effective for our customers, from whom we recover the costs of financing, to pay floating rather than fixed rates on this debt. If conditions were to change such that fixed rates were more favorable, the Company has the ability to change to fixed rates.

Note C - Nuclear Investments, page 29

The table in Note C summarizes the financial information, including equity in net income, furnished by Yankee Atomic Electric Company, Connecticut Yankee Atomic Power Company and Maine Yankee Atomic Power Company (together, the Yankees) and Vermont Yankee Nuclear Power Corporation. The equity in net income shown in Note C for the year ended March 31, 2005 pertains only to the Yankees. It will not reconcile with the equity in income of nuclear power companies shown on the Statement of Income for the year then ended because the latter also includes our equity in net income from our investments in New England Hydro-Transmission Electric Company and New England Hydro-Transmission Company (together, the Hydros). Please see the supplemental reconciliation table below.

The Company has an equity investment in the Yankees which in turn are the direct owners of the nuclear power plants. As such, we are not conducting decommissioning operations; we pay a share of decommissioning costs under power contracts with each of the Yankees. We reflected our entire nuclear decommissioning obligation in non-current liabilities on the balance sheet in "Accrued Yankee nuclear plant costs" with an equivalent amount recorded to "Regulatory assets". As stated in "Note D - Commitments and Contingencies" of the Notes to Financial Statements, the decommissioning liability is based on estimated costs. Because uncertainty exists in terms of the amount and timing of the payment of our liability, the Company reflected this liability as long-term. This treatment is consistent with other utilities' treatment of such obligations. Furthermore, the classification of the equal and opposite balance in "Regulatory assets" is recorded as non-current in accordance with the uniform system of accounts for regulated electric utilities.

Note H - Employee Benefits, page 48

21. As part of our review, we compared your assumptions used to determine your pension and PBOP expense with the assumptions disclosed in Niagara Mohawk's Form 10-K. We note differences in the discount rates used to determine your 2003 pension and PBOP expenses. We also noted a difference in the expected long-term return on plan assets used to determine your pension expense for 2003. Please explain why such differences exist.

The assumptions to determine pension and PBOP expense disclosed in the column for 2003 for the Company are incorrect. We used the same assumptions to determine 2003 pension and PBOP expense as those disclosed in Niagara Mohawk Power Corporation's Form 10-K, and they are correctly reported in the Company's Form 10-K for the fiscal year ended March 31, 2003.

Note J - Segments, page 46

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 electricity transmission. The segments disclosed are electricity-transmission and stranded cost recoveries.

Paragraph 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 used 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.

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.

Equity in Net Income Reconciliation
	Year Ended
(in thousands)	March 31, 2005

Equity in net income from the Yankees per Note C	$1,086
Yankees timing adjustment	89
Equity in net income from the Hydros	94

Equity in income of nuclear power companies per the Statement of Income	$1,269