SEC Comment Letter

NORTHEAST UTILITIES
107 Selden Street
Berlin, Connecticut 06037-1616

June 19, 2007

BY EDGAR AND FACSIMILE (202-772-9202)

Mr. Jim Allegretto, Senior Assistant Chief Accountant

Mr. Robert Babula, Staff Accountant

United States Securities and Exchange Commission

Division of Corporation Finance

100 F Street, NE

Washington, D.C. 20549

Subject:

Comment Letter - Northeast Utilities Form 10-K, For the Year Ended December 31, 2006, Filed on February 28, 2007

File No. 1-5324

The Connecticut Light and Power Company

File No. 0-00404

Public Service Company of New Hampshire

File No. 1-6392

Western Massachusetts Electric Company

File No. 0-7624

Gentlemen:

Northeast Utilities (NU), The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO) (collectively referred to herein as the "Company") have received your letter dated June 5, 2007 with respect to the review by the Securities and Exchange Commission (SEC or the "Commission") Staff of the above-referenced filing. Attached are our responses to your comments.

For your convenience, each of the numbered comments in your letter are repeated in this letter (boldface type) with the Company's responses set forth immediately below each such comment.

Please contact me with any additional questions or requests that you may have.

Sincerely,



		/s/ Shirley M. Payne
		Shirley M. Payne
		Vice President - Accounting and Controller

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FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2006

General

Our review encompassed the parent company, and the other subsidiary registrants listed on the facing page of your Form 10-K. In the interests of reducing the number of comments, we have not addressed each registrant with a separate comment. To the extent a comment is applicable to more than one registrant; please address the issue separately for the affected reporting subsidiary. The following page number references are from your 2006 Annual Report.

Response:

In providing the responses below we have addressed issues separately for each registrant to the extent applicable.

Financial Condition and Business Analysis, page 16

You indicate that NU Enterprises lost $62.9 million after taking into consideration the after-tax gain and loss on the sale of the competitive generation business and the retail marketing business, respectively. We were unable to reconcile to the amount presented in this disclosure. Please advise.

Response:

A reconciliation of the NU Enterprises $62.9 million loss, excluding the after-tax loss related to the sale of the Retail Marketing business and the after-tax gain on the sale of the Competitive Generation business for NU Enterprises, is as follows (in millions of dollars):


Total NU Enterprises segment 2006 earnings (1)		$ 211.3
Less: After-tax loss on sale of Retail Marketing (2)		32.8
After-tax gain on sale of Competitive Generation (3)		(307.0)
Net NU Enterprises 2006 Loss		$ (62.9)

(1)

Page 96 of NU's 2006 annual report.

(2)

Page 16 of NU's 2006 annual report.

(3)

The $307.0 million gain represents the portion of the total $314.1 million (disclosed as "approximately $314 million" on page 16 of NU's 2006 annual report) NU consolidated gain on the sale of the Competitive Generation business that was realized by NU Enterprises. In 2000, we improperly eliminated $7.1 million of deferred income tax liabilities in accounting for the sale of certain generation assets by some of our regulated subsidiaries to a competitive energy subsidiary. We discovered this improper elimination in 2006 when the same generation assets were sold to a third party and corrected this item by including the correction in the gain on sale in eliminations. See the response to comment number 3 below for a description of this $7.1 million and our conclusions thereon.

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NU Enterprises, page 19

Please supplementally explain the reason for the difference between the amount of earnings from discontinued operations for 2006 of $337.3 million from the reported amount on your Consolidated Statements of Income of $344.4 million for the 2006 period.

Response:

The difference between the amount of 2006 earnings from discontinued operations for NU Enterprises of $337.3 million on page 19 and the reported amount for NU consolidated of $344.4 million for 2006 on the Company's Consolidated Statement of Income is $7.1 million, which is included in the eliminations column of the segment footnote on page 96 of NU's 2006 annual report.

In 2000, certain generation assets were sold by CL&P and WMECO (registrants and wholly-owned subsidiaries of NU) to Northeast Generation Company (NGC), a non-utility, wholly-owned subsidiary of NU. As this was an intercompany sale, eliminations were established to properly reflect the sale on NU's consolidated financial statements. In 2000, we improperly eliminated $7.1 million of deferred income tax liabilities. We discovered this improper elimination in 2006 when the same generation assets were sold to a third party. We corrected this item by including the correction in the gain on sale. Since this was an elimination item, the financial statements for both CL&P and WMECO were appropriately stated for all periods, and the item only impacted NU consolidated. As the $7.1 million directly related to the generation assets, the sale of which was included in discontinued operations, the correction of the elimination item was also included in discontinued operations.

In evaluating the correction of the elimination item and the impact on 2006 financial statements, we performed an analysis considering the guidance provided in SAB 99 and SAB 108. Based on this guidance and on the following quantitative and qualitative factors, we do not believe that the annual financial statements, which included the impact of this item, were materially misleading for any period presented in our 2006 annual report.

We believe that the correction of the $7.1 million item in 2006 is not material when compared to the $337.3 million in total NU Enterprises discontinued operations income that was reported in 2006 or the $470.6 million of NU net income reported in 2006 (the item represents approximately 2 percent and approximately 1.5 percent of NU Enterprises discontinued operations income and NU net income in 2006, respectively). A year 2000 restatement would have increased opening retained earnings and decreased deferred income tax liabilities by $7.1 million (the item represents approximately 0.9 percent and approximately 0.6 percent of opening retained earnings and deferred income taxes, respectively).

Qualitatively, the small magnitude and nature of the correction of the item was such that we believe that the judgment of a reasonable person relying upon NU's financial statements would not have been changed or influenced by the item. The correction of the item did not mask a change in earnings or other trends and did not hide a failure to meet analysts' consensus expectations for NU or its segments. Other qualitative factors considered included:

The correction of the item did not change a loss into income;

The correction of the item did not cause the breach of any requirements, loan covenants or other contractual requirements;

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The correction of the item did not involve concealment of an unlawful transaction;

The correction of the item did not affect management's compensation (bonuses or other forms of incentive compensation);

The item did not result in a material weakness or a significant deficiency that was unremediated at December 31, 2006; and

The item relates to the NU Enterprises segment that is being divested and will not be significant to our operations or profitability going forward.

Another factor considered under SAB 99 and SAB 108 was whether the item arose from an item capable of precise measurement or whether it arose from an estimate and, if so, the degree of imprecision inherent in the estimate. Although the item can be precisely measured, we believe the factors above outweigh this factor.

In future filings, we can undertake to provide enhanced disclosures of the 2006 correction of the $7.1 million item to the extent it would be meaningful to the financial statement reader.

1. Summary of Significant Accounting Policies, page 58

F. Utility Group Regulatory Accounting, page 60

Deferred Benefit Costs, page 62

Please explain to us how you are recovering pension and OPEB expenses as of your last rate case and any updates. We presume the lack of a regulatory asset/liability prior to year-end 2006 means the full expense under SFAS no. 87 and 106 are included in rates. If our assumption is incorrect, please explain how each state PUC allows you to recover such expenses.

Response:

In all jurisdictions, we have historically requested rates in rate cases sufficient to recover full pension and OPEB expenses determined by our actuary and in accordance with applicable accounting pronouncements. We have a documented history of recovery of pension and OPEB expenses as approved by each regulator. We do not expect this regulatory approval to change in any of our jurisdictions. Your assumption is correct that the lack of a regulatory asset/liability prior to year end 2006 means the expenses determined in accordance with SFAS No. 87 and SFAS No. 106 are included in rates in all jurisdictions. An explanation of the recovery of pension and OPEB expenses by regulator is as follows:

Federal Energy Regulatory Commission (FERC)

Transmission Segments of CL&P, PSNH and WMECO: The FERC approves rates for the transmission segment. The FERC-approved tariff provides for the recovery of actual transmission operating expenses, including pension and OPEB costs as calculated under SFAS No. 87 and SFAS No. 106, as well as an allocated portion of the pension and OPEB expenses of NU’s service company subsidiary, Northeast Utilities Service Company (NUSCO). Transmission costs charged to NU's distribution companies are then fully recovered from distribution customers.

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Connecticut Department of Public Utility Control (DPUC)

CL&P's Distribution Segment: In CL&P’s most recent (December 2003) and previous rate cases, the DPUC approved recovery of CL&P’s pension and OPEB costs as calculated under SFAS No. 87 and SFAS No. 106, as well as an allocated portion of the pension and OPEB expenses of NUSCO. We expect consistent treatment of these costs in CL&P's next rate case, which will be filed in 2007.

Yankee Gas Services Company (Yankee Gas): In Yankee Gas’ most recent rate case settlement (December 2004) and in its previous rate cases, the DPUC approved recovery of Yankee Gas’ pension and OPEB costs as calculated under SFAS No. 87 and SFAS No. 106, as well as an allocated portion of NUSCO’s pension and OPEB expenses. In addition, a settlement agreement is currently pending approval by the DPUC for new rates effective on July 1, 2007, which continue to provide for the full recovery of pension and OPEB expenses.

Massachusetts Department of Public Utilities (DPU)

WMECO's Distribution Segment: In WMECO’s most recent rate case settlement (approved in December 2006 for rates that became effective on January 1, 2007) and in its previous rate cases, the Massachusetts Department of Telecommunications and Energy (now known as the DPU) approved recovery of WMECO’s pension and OPEB costs as calculated under SFAS No. 87 and SFAS No. 106, as well as an allocated portion of NUSCO’s pension and OPEB expenses. The recent settlement agreement also included regulatory approval of the use of a pension and OPEB cost tracking and recovery mechanism.

New Hampshire Public Utilities Commission (NHPUC)

PSNH: In PSNH’s May 2004 and previous rate cases, the NHPUC approved recovery of PSNH’s pension and OPEB costs as calculated under SFAS No. 87 and SFAS No. 106, as well as an allocated portion of NUSCO’s pension and OPEB expenses. On May 25, 2007, the NHPUC approved new rates under a rate case settlement effective on July 1, 2007, which continue to provide for the full recovery of pension and OPEB expenses.

3. Assets Held for Sale and Discontinued Operations, page 69

We note the disclosure regarding not presenting the retail marketing business as a discontinued operation. Explain why it does not qualify for such treatment. If it is not considered a component of an entity due to paragraph 41 of SFAS no. 144, explain in detail how management evaluated the performance of these assets.

Response:

The Retail Marketing business (Retail) does not qualify for discontinued operations treatment because prior to 2006 its operations and cash flows were not separately identifiable from those of the Wholesale or Generation operations for financial reporting purposes.

Until 2006, the operations and cash flows of Retail and Wholesale were integrated. Retail and Wholesale shared employees, and their cash flows and expenses were commingled. Retail was supplied by Wholesale supply contracts through March 31, 2005. Subsequent to that date and

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until early 2006, Retail was supplied by Generation. Retail’s internal supply arrangements with Wholesale and Generation were not settled in cash, and were reflected in management reports using internal transfer prices that were not indicative of current market prices that Retail would have paid an external third party for its supply. Although Retail’s cash flows were integrated with and largely indistinguishable from those of Wholesale and then Generation, management evaluated the performance of Retail operations by reviewing results based on allocated expenses and transfer prices. The Retail results prepared for management were not adequate for public segment reporting purposes.

Beginning in early 2006, after the disposition of much of Wholesale and after the Generation assets were decoupled from Retail in preparation for sale, Retail’s operations and cash flows were segregated. Retail separately purchased power from third parties and had its own separately identifiable operations and employees. Retail was considered a component because it then had operations and cash flows that could "be clearly distinguished, operationally and for financial reporting purposes" (paragraph 41 of SFAS No. 144). Because it met the "held for sale" criteria, the Retail component was classified as held for sale in the first quarter of 2006.

Beginning in the first quarter and for all quarters in 2006 we were able to and began to provide separate Retail financial information to management without use of significant allocations or transfer prices from Wholesale or Generation. This new standalone financial information was the basis for presenting Retail as a reportable segment in our 2006 segment disclosures.

Although Retail was held for sale and had distinguishable financial information beginning in the first quarter of 2006, it did not qualify for discontinued operations presentation because Retail information, based on separately identifiable operations and cash flows, was not available for years prior to 2006. Accordingly, we could not prepare comparable prior year information that is required for discontinued operations presentation and do not believe that including the discontinued operations presentation for 2006 only would have been appropriate under the guidance in SFAS No. 144.

Please tell us how and whether you allocated interest expense associated with the discontinued operations. We assume you allocated actual expense of assumed debt. Please tell us whether any other allocations of interest expense were made and the method you utilized. Please note the disclosure requirements of EITF 87-24. As a final note, to the extent interest allocations of discontinued operations affected interest expense of continuing operations, this should be analyzed in management's discussion and analysis of interest expense. In this regard, the utilization of proceeds from the dispositions to pay down debt should also be addressed in the discussion to the extent it impacts interest expense. Please advise.

Response:

We elected to only include interest expense that was directly attributable to or related to discontinued operations within discontinued operations results, as allocating other consolidated interest expense to discontinued operations is permitted but not required. The interest expense that was included in discontinued operations related to debt that was assumed by the buyer of the generation assets. No debt was required to be repaid as a result of the sale of generation assets. As we elected not to allocate other consolidated interest expense to discontinued operations, the disclosure requirements of Emerging Issues Task Force Issue No. 87-24,

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"Allocation of Interest to Discontinued Operations," were not applicable, and a discussion of interest expense allocated to discontinued operations in the results of operations disclosures was not necessary.

Regarding the use of proceeds and the impact on interest expense, we included a discussion of the utilization of proceeds as a result of the sales of the NU Enterprises businesses and the associated liquidity impacts in the Liquidity section of the MD&A on page 21 of NU's 2006 annual report. Short-term debt was repaid, but was not required to be repaid by the sale of generation assets.

5. Derivative Instruments, page 70

We note the discussion on page 72 regarding the contracts with two IPP's. Please provide to us a summary description of the power purchase contracts and related accounting analysis, including the pricing provisions that disqualified the contracts for the normal purchases and sales exception. If the pricing provisions are not customary within the industry, or contain higher than normal risk, then please support the probability of recovery as a prudent cost.

Response:

The Independent Power Producers (IPP) contracts are CL&P contracts to purchase energy and capacity from two plants in the state of Connecticut. One contract was entered into in December of 1985 and will remain in effect until March of 2015. The second contract was entered into in June of 1991 and will remain in effect until December of 2020. These contracts were entered into under the Connecticut statute implementing the Public Utility Regulatory Policies Act (PURPA), which required CL&P to purchase power from IPPs that were qualifying facilities. The energy and capacity received under these contracts were part of CL&P's supply when it was a vertically integrated utility responsible for the generation or purchase of power, as well as transmission and distribution. Now CL&P has no generation, and these IPP contracts are stranded costs, as defined by the Connecticut statute implementing industry deregulation.

Consistent with PURPA, the pricing of the contracts was based on CL&P's avoided cost, which was the specific fuel cost of certain CL&P generation assets. The pricing provisions for the two IPP contracts include a "Gross National Product Implicit Price Deflator." We do not apply the normal purchases and sales exception to these contracts because DIG Issue No. C-20, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature," precludes normal accounting treatment when the pricing of a derivative is not clearly and closely related to the asset delivered under the contract. DIG Issue No. C-20 holds that a price adjustment feature such as a GNP Implicit Price Deflator would not be clearly and closely related.

The avoided cost pricing of these contracts is customary to qualifying facility contracts under PURPA and does not represent a higher than normal risk. The pricing, which was referenced to the cost of other generating plants that CL&P owned at the time, was appropriate when the contracts were entered into with the qualifying facilities when CL&P was a vertically integrated utility.

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Since deregulation, the costs of these contracts have been and continue to be recovered from ratepayers under a stranded cost tracking recovery mechanism. We believe that recovery of these costs will continue into the future as the IPP contract costs are specifically identified as a stranded cost by Connecticut statute, CL&P's stranded cost tracking recovery mechanism reconciliations have been approved by the DPUC annually and there have been no adjustments or challenges to the recovery of these costs.

6. Employee Benefits, page 73

Please tell us whether the establishment of the regulatory asset as a result of adoption of SFAS no. 158 had any impact on deferred taxes. If not, please explain why.

Response:

The establishment of the new regulatory assets as a result of the adoption of SFAS No. 158 had an impact on the deferred tax liabilities of NU, CL&P, PSNH and WMECO. The new regulatory assets recorded had no tax basis and therefore resulted in temporary tax differences that required deferred tax liabilities to be recorded. In addition, the increase in the pension and OPEB liabilities created temporary tax differences for which deferred tax assets were recorded.

The tax footnote disclosures for these registrants (which are included on pages 63, 33, 16 and 14 in NU's, CL&P's, PSNH's and WMECO's respective 2006 annual reports) include these new long-term deferred tax liabilities, as well as the deferred tax assets created by the increase in the pension and OPEB liabilities. These amounts are netted on the consolidated balance sheet as required by SFAS No. 109, "Accounting for Income Taxes."

10. Marketable Securities, page 89

Please tell us whether there are any unrealized losses on available-for-sale securities held by WMECO's prior spent nuclear fuel trust assets. In this regard, please advise whether WMECO trust is subject to investment guidelines of the NRC. We may have further comment.

Response:

Yes, there are unrealized losses on available-for-sale securities held by WMECO's prior spent nuclear fuel trust. The pre-tax, unrealized losses on the WMECO spent nuclear fuel trust were $0.1 million at December 31, 2006 and $0.4 million at December 31, 2005. These losses, net of taxes, were included in accumulated other comprehensive income.

The trust is not subject to the investment guidelines of the NRC. The trust is not a decommissioning trust, but rather it was established to economically defease WMECO's spent nuclear fuel liability to the United States Department of Energy (DOE) for fuel burned prior to 1983. The marketable securities held in the trust and the obligation to the DOE are presented separately on WMECO's balance sheet. The obligation to the DOE is included in long-term debt. The trust was established as part of a specific petition on the part of WMECO that was approved by the DPU.

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In connection with the above responses to the Commission's comments, the Company hereby acknowledges that:

The Company is responsible for the adequacy and accuracy of the disclosure in the filing;

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

The Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

In addition, the Company further acknowledges that the Division of Enforcement has access to all information provided to the staff of the Division of Corporation Finance in connection with the filing.

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