NRG Energy, Inc. 211 Carnegie Center Princeton, NJ 08540
		Phone: Fax:		609-524-4702 609-524-4515

May 19, 2006

Securities and Exchange Commission
Division of Corporation Finance
Mail Stop 3561
450 Fifth Street, N.W.
Washington, D.C. 20549

Attn: Jim Allegretto, Senior Assistant Chief Accountant

		RE:		NRG Energy, Inc.
				Form 10-K for the year ended December 31, 2005
				Filed March 7, 2006
				File No. 1-15891
				Form 8-K/A filed on January 26, 2006
				File No. 1-15891

Dear Mr. Allegretto:

     We hereby respond to the comments made by the Staff in your letter dated May 3, 2006 relating to NRG Energy, Inc.’s (“NRG’s” or the “Company’s”) Annual Report on Form 10-K for the fiscal year ended December 31, 2005, filed on March 7, 2006 (the “Form 10-K”) and the Amended Current Report on Form 8-K/A filed on January 26, 2006 (the “Form 8-K/A”). We acknowledge that we are responsible for the accuracy and adequacy of the disclosure in the filings reviewed by the Staff to be certain that we have provided all information investors require for an informed decision. Since the Company and management are in possession of all the facts relating to the Company’s disclosure, we are responsible for the accuracy and adequacy of the disclosures we have made. We hereby acknowledge that (i) the Company is responsible for the adequacy and accuracy of the disclosure in the filings; (ii) Staff comments or changes to disclosures in response to Staff comments do not foreclose the Commission from taking any action with respect to the filings; and (iii) 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. We look forward to working with the Staff and improving the disclosures in our filings.

     The Staff’s comments, indicated in bold and NRG’s responses are as follows:

Mr. Jim Allegretto
May 19, 2006

Form 10-K for the year ended December 31, 2005

Item 1. – Market Framework, page 27

1.

Please explain how you are accounting for your long-term all requirements contracts with the 11 Louisiana distribution cooperatives. To the extent there are any minimum load requirements under the contracts, explain to us what consideration was given to DIG Issue A-6. If you concluded these contracts were derivatives, please explain whether and how you elected the normal purchases and normal sales exception. In this regard, you disclose that your assets are insufficient to satisfy the requirements of the customers under these contracts. Please explain to what extent you may be using a market mechanism to satisfy these contracts. Finally, please indicate to us the financial impact for the past three years as a result of not having sufficient load, or capacity to satisfy these contracts, or any other contracts that you have in place within your operating regions. We may have further comment.

The long-term contracts with the 11 Louisiana distribution cooperatives meet the definition of a “requirements contract” as outlined in DIG Issue A6, and are therefore not considered derivatives. That is, a notional amount (a minimum implicitly stated in the contract, a historical amount outlined in an appendix, or an amount referenced in the liquidating damages provisions) is not present in any of those contracts. Moreover, our long-term contracts require physical delivery of electricity, they do not contain provisions for financial settlement of our obligations and they do not allow power to be re-sold.

In respect to our disclosure of insufficient assets, we’d like to clarify that we do have the ability to satisfy customer requirements under these contracts, as the Company has the capacity to meet peak requirements in the South Central region. This is possible by utilizing our peaking assets, which are sufficient to cover contract load, but are often uneconomical to dispatch. As a result, we often elect to purchase power from other producers in the region instead of running these peaking plants. We estimate that the unfavorable financial impact to our gross margin from purchasing power at market and utilizing that power to satisfy load obligations was approximately $45 million, $12 million, and $10 million for the fiscal years ended 2005, 2004, and 2003, respectively.

Mr. Jim Allegretto
May 19, 2006

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 76

2.

Prospectively, if possible please discuss the impact that your interest rate swaps had on interest expense.

In accordance with the Staff’s comments, NRG will prospectively provide in future filings a discussion in respect to the impact of our interest rate swaps on interest expense within Management’s Discussion and Analysis of Financial Condition and Results of Operation. To illustrate, please see the discussion provided under Interest expense on page 50, Part I, Item 2 – Management’s Discussion and Analysis – Results of Operations, of our March 31, 2006 Form 10-Q filed on May 9, 2006 (the “First Quarter Form 10-Q”).

Note 13 – Investments Accounted for by the Equity Method, page 171

3.

Your summarized financial information for MIBRAG suggests your equity pick-up was 50% of net income, pre-tax. Please explain why you did not record your share of after-tax net income. Also, provide to us a reconciliation of the reported equity of $348 in your note disclosure to the amount reported on the audited financial statements in Euro. Please further reconcile that to the carrying amount of your investment. Please tell us whether net income has been adjusted to US GAAP, if not tell us why. Please be aware that you should be reporting the difference, if any, between the amount at which an investment is carried and the amount of underlying equity in net assets and the accounting treatment of the difference. See paragraph 20.a of APB no. 18.

The reported MIBRAG net income is after tax and not pre-tax as stated in Note 13 under the MIBRAG summarized financial information sub-heading “Results of Operations”. The Company will properly label this caption in prospective filings. Also, all amounts are reported on a U.S. GAAP adjusted basis.

MIBRAG reported equity of $348 million under the “Financial Position” section of this note that includes fresh start and U.S. GAAP adjustments, whereas the amounts reported in the MIBRAG audited financial statements as of December 31, 2005 included in Exhibit 99.2 of our Form 10-K/A filed on March 27, 2006, are on a German statutory, historical basis. We provided a table reconciling historical German statutory financial statements to U.S. GAAP, without fresh start adjustments as required by SOP 90-7 upon emergence from bankruptcy, in this exhibit. NRG’s 50% equity investment of approximately $174 million (50% of $348 million) includes fresh start and U.S. GAAP adjustments.

Mr. Jim Allegretto
May 19, 2006

All MIBRAG reported numbers on a 100% basis :

		Equity
		(in millions)
Note 13, page 173:
Euro			294
Exchange rate at 12/31/2005			1.184
US$ Equity reported in Form 10-K		$	348
Exhibit 99.2, page 14:
Euro			368
Exchange rate at 12/31/2005			1.184
US$ Equity Reconciled to US GAAP per audited financials in Form 10-K/A		$	436
Reconciling item = Fresh Start Adjustments per SOP 90-7 (principally Fixed Asset write downs) :
Euro			(74	)
Exchange rate at 12/31/2005			1.184
US$		$	(88	)

4.		Please show us your test of significance for Gladstone pursuant to Rule 1-02(w) of Regulation S-X. In this regard, please advise the necessity of providing audited financial statements pursuant to Rule 3-09 of Regulation S-X.

Significance test pursuant to Rule 1-02(w) in respect to our Gladstone investment as of and for the year ended December 31, 2005:

Equity earnings as a percent of income from continuing operations before income taxes:

		(in thousands)
Equity earnings in Gladstone investment		$	23,858
NRG income from continuing operations before income taxes		$	119,974
Ratio			19.88	%

Equity investment in Gladstone as a percent of NRG’s total assets:

Equity investment in Gladstone		$	162,659
NRG total assets		$	7,430,854
Ratio			2.18	%

In accordance with Rule 3-09 of Regulation S-X, we applied the first and third test of Rule 1-02(w) with a 20% threshold test. Due to the fact that the ratio was below the 20% threshold, we did not provide financial statements for our Gladstone investment as an exhibit to our Form 10-K, pursuant to Rule 3-09.

Mr. Jim Allegretto
May 19, 2006

Note 15 – Accounting for Derivative Instruments and Hedging Activities, page 177

5.

Explain to us what impact, if any, Hurricanes Katrina and Rita had on your anticipated sales of power in your South Central Operating Region in 2005. In this regard, explain if the company had any cash flow hedges in place related to anticipated sales, or purchases of power to satisfy your load requirements under the contracts. If you did have cash flow hedges in place, explain how you accounted for any lack of power delivered in this region and the related impact on the derivatives’ effectiveness. In this regard, you indicate on page 27 of your filing that four of you cooperative customers suffered extensive damage to their distribution systems.

For the twelve months ended December 31, 2005, the Company did not have any cash flow hedge relationships related to anticipated sales or purchases in the South Central region. This is consistent with the South Central operating strategy pursuant to which we do not typically engage in long-term forward sales of power, except for our existing requirements contracts.

Form 8-K/A filed on January 26, 2006

General

6.

Please provide a listing and individual analysis of any potentially material pre-acquisition contingencies. To the extent any potential pre-acquisition contingencies exist, they should be identified and discussed in the pro forma financial statements using the guidance contained in SAB Topic 2.A:7.

We did not discuss pre-acquisition contingencies in the pro forma statements because we did not expect to record a material adjustment to probable liabilities for the two identified, potentially material pre-acquisition contingencies, the California Electricity and Related Litigation (West Coast Power) and Texas Asbestos Litigation (Texas Genco). These contingencies are disclosed in the financial statements of the acquired entities included in exhibits listed in Item 9.01 of the Form 8-K/A. These matters are also disclosed in Note 15 of our First Quarter Form 10-Q. No probable liabilities were recorded on the acquired entities balance sheets and, to date, we have not established probable liabilities associated with these contingencies in purchase accounting and we are unable to estimate a range of probable loss at this time.

With regard to the California Electricity and Related Litigation, NRG considers the likelihood of an adverse decision to be reasonably possible, but not estimable. Thus, the contingent liability is subject to disclosures only.

Settlements related to claims under the Texas Asbestos Litigation have occurred, but have not been material to date. The Company is considering engaging an actuary to assist in the estimate of pending claims and may establish a reserve in our final purchase price allocation. However, such amount is presently not expected to be material.

Mr. Jim Allegretto
May 19, 2006

Transactional Pro Forma Analysis, page 5

7.

You indicate on page six that the purchase price and allocation may change significantly from the pro forma amounts included in this filing. Please note that any material differences between the adjustments reflected in these pro forma financial statements and those made at closing of the acquisition should be identified and discussed in the historical financial statements in which the purchase is first reflected. This may be accomplished in the note in which you provide the paragraph 51.e of SFAS 141 disclosure. Please ensure you identify differences due to external factors such as interest rates or changes in the position of commodity forward curves versus those due to factors largely within your control, such as changes in estimates, appraisals, discount rates or identification of additional contingencies or assets. Please confirm your concurrence with this approach and explain to us how you plan to communicate changes in your allocation of purchase price at closing.

While we are unaware of any SEC Rule, SEC Staff directive or GAAP requirement to identify the pro forma financial statements to the actual purchase accounting reflected in the historical financial statements, in accordance with the Staff’s comments, NRG confirms its concurrence with the approach described above. We will prospectively provide a discussion in future filings with respect to the material adjustments related to the purchase price allocation and we will disclose the changes to external factors that contributed to such adjustments and other changes due to factors largely under our control.

In this regard, we refer the Staff to page 10, Note 4 – Business Combinations, of our condensed consolidated financial statements included in our First Quarter Form 10-Q. We believe this disclosure is consistent with this approach and we will continue to prospectively modify this disclosure as necessary.

Purchase Price Allocation, page 7

8.

Please describe in detail your process for identifying all acquired identifiable intangible assets. Given the substantial amount of goodwill recorded on this transaction, we believe it is possible that there may be additional intangibles that may have been overlooked in allocating fair value. In this regard, please tell us in detail the reasons you paid a substantial premium relative to the allocated net fair value. In this regard, describe your strategic reason(s) for this acquisition. Please address any synergies and the limitations associated with generation in ERCOT. Your existing purchase price allocation of approximately 39% of goodwill appears high given this business acquisition is closer to an asset acquisition. Please advise in detail.

The purchase price paid for Texas Genco LLC was based on its near term substantially hedged portfolio with stable cash flows and a longer term, conservative view on forward curve gas prices that declined to approximately $7/mmBtu near the end of the curve in 2011. Our purchase price was determined, in part, by a gas price

Mr. Jim Allegretto
May 19, 2006

in the terminal year of $5.50/mmBtu. The $8.3 billion announced enterprise value (inclusive of debt assumption) divided by Texas Genco LLC’s expected earnings in 2006, resulted in a purchase price multiple below NRG’s trading multiple at the date the acquisition was publicly announced. Furthermore, this $8.3 billion value was before approximately $500 million in after-tax cash benefits that are expected to result from the increased tax basis of the acquired assets. With Texas Genco LLC, NRG increased its U.S. generation portfolio with high quality, relatively newer, baseload plants with capacity that improved fuel, dispatch and geographical diversity of our plant portfolio. The acquisition provided the Company with a strong asset position in all of the key competitive wholesale markets in the United States, including the Northeast, South Central, California and Texas. Prior to the acquisition, NRG had no presence in the ERCOT market. Synergies are limited by the inability to export generation from ERCOT. Notwithstanding generation limitations, the Company believes potential future synergies are available from the combined fuel procurement and transportation and asset management processes.

The process followed to identify all acquired intangible assets involved a thorough review of all contracts and legal rights to identify intangibles arising from the “contractual-legal criterion” of FAS 141, paragraph 39. We conducted an initial review of material contracts during due diligence followed by a thorough review after closing, in conjunction with the appraisal process. We also searched for any intangibles that met the “separability criterion” of paragraph 39 in conjunction with the appraisal process. During the appraiser selection process in late 2005, we interviewed seven consulting firms and asked each about the steps they would follow to identify acquired intangibles apart from goodwill in a power industry acquisition. These interviews helped us to better understand the existence and nature of potential intangibles in our industry. Also, Texas Genco LLC was subject to provisions of FAS 141 as a result of business combinations when formed in 2004. NRG reviewed the appraisal report Texas Genco LLC used in its purchase price allocation and also reviewed its 2004 and 2005 audited financial statements in order to further identify potential intangibles. Upon closing, the Company engaged Duff and Phelps to assist us in the identification and quantification of identifiable intangibles. NRG subsequently disclosed a detailed list of identifiable intangibles that resulted from the above process in Note 4 – Business Combination, on page 11 of our First Quarter Form 10-Q.

The Company understands the Staff’s comment above to be based on the pro forma purchase price allocation summarized on page 7 of the Form 8-K/A, which resulted in the approximately 39% ($2,371 goodwill/$6,121) pro forma purchase price allocation to goodwill. NRG viewed the pro forma allocation from the perspective that $4,943 million allocated to fixed assets plus $1,309 million allocated to emission credits exceeded 100% of the $6,121 million to be allocated. NRG did not have the benefit of an appraisal report during the preparation of the pro forma purchase price allocation.

Mr. Jim Allegretto
May 19, 2006

The single largest factor supporting the preliminary goodwill disclosed in our First Quarter Form 10-Q, is the attribution of a significant portion of the value of the two coal fired generation business units to favorable market conditions at the date of acquisition, combined with the limitation of value attributable to the plant and equipment to the depreciated replacement cost (DRC), plus a premium for immediate use. The values of the two coal fired generation business units are greater than the DRCs including a premium for immediate use, but the DRC plus the premium is considered the upper limit of the plant and equipment value. The additional value is attributable to favorable market conditions. The immediate use value was included to consider the fact that under certain circumstances (such as the favorable market conditions) investors will pay a premium for certain assets. Although the replacement cost of an asset is often considered to be the upper limit one would pay for an asset, since the favorable market conditions might only exist for a limited period of time and since it often takes a significant amount of time to construct a replacement asset, an investor would be willing to pay a premium for an asset under these circumstances to take advantage of the existing favorable market conditions. The immediate use value is measured as the present value of the expected “excess” future cash flows over the expected time frame to construct a replacement asset. The “excess” cash flows are measured as the cash flows beyond those of a normal return on an investment in a replacement plant (or a return on the DRC of the subject plants in the case of the existing, older plants).

Based on our preliminary valuation, the favorable market conditions for these solid fuel plants is due to the substantial fuel advantage these plants have relative to natural gas fired generation with the current and expected continuation of high natural gas prices. The power prices in the ERCOT market are largely driven by the natural gas prices as the marginal market power requirements are met by gas-fired, combined cycle plants. We expect this to continue for the foreseeable future in ERCOT, since a substantial majority of the generation is gas fired and we believe it would require an extended period of time to transition to alternative fuels that could have an effect on the future price expectations. We anticipate that the two coal fired generation businesses will benefit from the higher power prices driven by the gas prices and the relatively lower cost of coal for an indefinite period of time. The favorable market conditions are not considered a separable intangible asset and are, therefore, the major contributor to the amount of goodwill.

9.

Please tell us the amount of the adjustment to the pension and postretirement obligations and your method of computation. To the extent you utilize or expect to utilize a current actuarial valuation, please tell us the date of such valuation, all the principle assumptions and whether you anticipate updating the valuation upon closing. Please explain to us what consideration you have given to anticipated settlements due to early retirement options in measuring the projected benefit obligation.

The Company did not include any pro forma adjustments for pension and postretirement obligations in our Form 8-K/A. Our actuary was not engaged at the time the pro forma purchase price allocation was performed, thus we had no basis for an estimate.

Mr. Jim Allegretto
May 19, 2006

Upon closing the Texas Genco LLC acquisition on February 2, 2006, we hired our actuary, Hewitt Associates LLC, or Hewitt, to assess the fair value of the outstanding pension and postretirement obligation of Texas Genco LLC. The liability determined in this valuation was based on the Texas Genco LLC census data collected as of January 1, 2006. The data included all active employees as of January 1, 2006 who were covered in the pension and retiree welfare plans as well as all inactive participants who are currently receiving benefits from the plan and all terminated vested participants who are no longer employed by Texas Genco LLC, but are vested in a pension or retiree welfare benefit. The liability was calculated using NRG’s valuation assumptions that were set as of December 31, 2005 for FAS 132 disclosure purposes. These include:

		Pension Benefits				Postretirement
Discount rate			5.50	%			5.50	%
Rate of compensation increase			4.00 - 4.50	%			n/a
Health care trend rate			n/a			11.5% grading to 5.5% in 2012
Expected return on plan assets			8.00	%			n/a

Note that the inactive participant group includes all the former Texas Genco LLC employees who terminated during 2005 under a special early retirement incentive program the acquired business called the Voluntary Retirement Option. NRG’s purchase accounting liability, or PBO, reflects the full value of all the additional pension and retiree welfare benefits that were provided to this group in 2005.

No other participants are entitled to any special early retirement enhancements at this time. Thus, we do not anticipate any special settlements or enhanced termination benefits will be provided to the current active population at this time.

Hewitt provided NRG with its report on March 15, 2006, and this report was reviewed and approved by NRG’s management team. The results of this report are reflected in the purchase price allocation found in Note 4 – Business Combinations, in our First Quarter Form 10-Q. The report resulted in an increase to the balance of Texas Genco LLC’s pension and postretirement obligation by approximately $16 million.

10.

Please describe in detail the assumptions and modeling method used in determining the fair market value of Texas Genco’s out-of-the money power contracts. Explain to us how you obtain forward market curves for energy prices including whether they are internally derived or based on outside sources. If outside, identify the source. Tell us whether the forward curves are or were used for other business purposes; such as entering into contracts for purchase and sale of the specified commodity in a given market. Tell us whether the same forward curve is used for sales versus purchases for a given commodity at a given delivery point. If not, please explain why.

Mr. Jim Allegretto
May 19, 2006

The methodology employed to estimate the value of the out-of-the-money power contracts for the pro-forma analysis included on Form 8-K/A was a discounted cash flow method. The cash flow attributed to the power contracts was estimated as the difference in the revenue from expected future power sales based on the terms of the contracts relative to the expected revenue as if the contracts had been at market as of October 24, 2005. The difference in revenue is also over the remaining term of each of the contracts. These cash flows were then discounted to their present value using an appropriate 1 month, 3 month, 6 month, 1 year, LIBOR rates or expected 2 year, 5 year, 10 year LIBOR rates.

The assumptions of volumes, contract prices and remaining terms of each of the contracts are based on the contract terms. The other key assumptions include the outlooks for the market power prices and the discount rate. The outlooks for the market power prices for each of the regions within ERCOT (Texas Genco LLC operates in the North, South and Houston regions of ERCOT) are based on Texas Genco’s internal pricing model.

Duff & Phelps, our valuation consultants, employed the same methodology with somewhat different assumptions, for the preliminary valuation as reflected in our First Quarter Form 10-Q. Their methodology and assumptions are explained in detail below.

The methodology employed to estimate the fair value of the out-of-the-money power contracts for the preliminary allocation was also a discounted cash flow method. This is the same methodology that we used to value the business units of Texas Genco LLC to negotiate the purchase price. It is consistent with the methods used to allocate the purchase price by carving-up the cash flows attributable to each of the acquired assets or asset groupings and discounting to their present value.

The cash flow attributable to the power contracts was estimated as the difference over the remaining term of each of the contracts between: 1) the revenue from expected future power sales based on the terms of the contracts; and 2) the expected revenue as if the contracts had been at market as of the closing date. This difference in revenue was considered attributable to the contracts. The difference in revenue is also the same as the difference in pre-tax income and cash flow since all of the operating costs remain the same. Taxes are then estimated and deducted to estimate after-tax cash flows. These cash flows were then discounted to their present value using a Weighted Average Cost of Capital (WACC), as considered appropriate for such an investment in an independent power production business, and the related contracts or assets.

The assumptions of volumes, contract prices and remaining terms of each of the contracts are based on the contract terms. The other key assumptions include the

Mr. Jim Allegretto
May 19, 2006

outlooks for the market power prices, the tax rate and the discount rate. The outlooks for the market power prices for each of the regions within ERCOT (Texas Genco operates in the North, South and Houston regions of ERCOT) are based on an internal NRG pricing model, tested for reasonableness with comparable power pricing forecasts prepared by Platts, a division of The McGraw Hill Companies. This same power price model is used by NRG for business planning purposes including budgeting, projections, etc. and for acquisition, investment and sales analysis including new plant investments/expansions or upgrades, new contract considerations and acquisitions such as the Texas Genco LLC acquisition. The output from the price model is compared to the futures prices within the ERCOT market for reasonableness. The ERCOT market has adequate liquidity in the near term and extends out for approximately three years. Approximately 91 % of the value of the out-of-the-money power contracts is derived from the three year liquid period. Therefore, the overall value of the contracts is not particularly sensitive to the longer-term view of the power market.

An effective tax rate of 35% was assumed. A WACC of 8.5% was assumed based on a weighting of the cost of equity from the Capital Asset Pricing Model using independent power producers as guideline companies and an after-tax cost of debt.

Our consultants have tested the key assumptions for reasonableness by computing the net present value of the cash flows across all of the business units, which was reasonably reconciled to the purchase price for Texas Genco LLC. The same business unit cash flows, tax rates and discount rates were the same assumptions used as a starting point for the analysis and carve-out of the out-of-the-money contracts.

11.

We note the future amortization of the out-of-the money power contracts is material to your financial statements. Please explain how you intend on communicating such non-cash income in MD&A.

As noted by the Staff’s comment, the balance of out-of-the-money power contracts is material to our financial statements, as well as the annual amortization of such contracts. We refer the Staff to Page 46, Part I, Item 2 – Managements Discussion and Analysis – Results of Operations, of our First Quarter Form 10-Q. We have broken out the different revenue streams including power contract amortization, disclosing the effect by segment of such amortization. We have also discussed such amortization in our analysis on page 51. In addition, we expect to disclose the expected amortization of all acquired intangibles by year through 2011 and thereafter in our 2006 annual report on Form 10-K. We believe these disclosures are adequate and intend to continue to modify them as necessary.

Mr. Jim Allegretto
May 19, 2006

III. Acquisition of WCP and Sale of Rocky Road, page 14

12.

We note you purchased the remaining 50% of WCP for approximately $205 million. We presume your existing equity interest in WCP received a new basis in the fresh start accounting applied in December, 2003. We further assume you considered other-than-temporary losses in value of your equity interest subsequent to new basis accounting. Please tell us the new basis established in fresh start and how that value was determined. Also describe in detail any other-than-temporary loss in value analysis performed after new basis but before acquisition of the remaining 50%. If your carrying amount prior to acquisition of the remaining 50% of WCP exceeded the acquisition price of the remaining 50%, please explain in detail how any prior analysis was in accordance with paragraph 19.h of APBO no. 18. We may have further comment.

Upon Fresh Start in 2003, we revalued our investment in WCP on the basis of a discounted cash flow for expected dividends projected from the project and recorded a write-down of approximately $69 million to a carrying value of $253 million. Consequently, we established two basis differences:

	1.		An impairment to fixed assets of approximately $193 million
	2.		An intangible asset related to a positive power contract with the California Department of Water Resources in the amount of approximately $125 million. This contract expired on December 31, 2004 and we fully amortized this basis difference as of such date through our equity earnings. The value of the embedded intangible asset was derived based on a discounted cash flow analysis when compared to the then-current market prices.

Subsequent to Fresh Start, we annually assessed our WCP investment for impairment and concluded that there was no other-than-temporary loss in value because:

	A.		We continued to receive dividends on a regular basis from WCP
	B.		WCP continued to report net earnings.

In December 2005 when the acquisition of the remaining 50% interest was announced, we compared our investment balance of approximately $158 million to the purchase price of $205 million for the remaining 50% and again concluded that there was no other-than-temporary loss on our equity investment at that time.

*      *      *      *      *      *

Mr. Jim Allegretto
May 19, 2006

     We hope that we were able to clarify your comments and eagerly await the Staff’s response. Please contact James Ingoldsby, Controller, at (609) 524-4731 or me at (609) 524-4702 if you have questions regarding our responses or related matters.

cc:		H. Christopher Owings, Assistant Director, Securities and Exchange Commission Robert Babula, Staff Accountant, Securities and Exchange Commission Timothy W. J. O’Brien, General Counsel, NRG Energy, Inc. James J. Ingoldsby, Controller, NRG Energy, Inc.