SEC Filing | NRG Energy, Inc.

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S.E.C. RESPONSE LETTER

(NRG LOGO)

NRG Energy, Inc.
211 Carnegie Center
Princeton, NJ 08540

Phone: 609-524-4591
Fax: 609-524-4589

May 6, 2005

Securities and Exchange Commission
Division of Corporation Finance
Mail Stop 0308
450 Fifth Street, N.W.
Washington, D.C. 20549


Attn:	H. Christopher Owings, Assistant Director


RE:	NRG Energy, Inc. Registration Statement on Form S-3 Filed March 30, 2005 File No. 333-123677 Annual Report on Form 10-K for the Period Ended December 31, 2004 Filed March 30, 2005 Preliminary Proxy Statement on Schedule 14A Filed March 30, 2005 File No. 1-15891

Dear Mr. Owings:

We hereby respond to the comments made by the Staff in your letter dated April 29, 2005 relating to NRG Energy, Inc.’s (“NRG” or the “Company”) Annual Report on Form 10-K for the Period Ended December 31, 2004, filed on March 30, 2005 (the “Form 10-K”). 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 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. H. Christopher Owings
May 6, 2005

Form 10-K

Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations

Revenue from Majority-Owned Operations

Reorganized NRG, page 55

In future filings please provide a more detailed discussion, by reportable segment for each component of revenues from majority-owned operations. We understand given the reorganization of the company that a year over year analysis comparing 2004 to 2003 that discusses and quantifies the changes in the components of revenues may be difficult or non-beneficial to the reader; however, we would expect there to be a more in depth discussion and quantification of the changes in future periods. For example, a discussion and quantification of the change in megawatt hours, rates, temperature, plant outages and other factors that both positively and negatively impact revenues from year to year with a focus on trends and uncertainties will allow a reader to better understand your revenues. Additionally, as it relates to capacity revenues, with the exception of the RMR agreements, you indicate that other agreements lead to the generation of revenues for particular regions however you do not provide the amounts that these agreements contributed for the periods presented or the length of time you expect these agreements to continue to contribute to the revenues of those segments. For example, you indicate that long-term contracts provide for capacity payments in the South Central region and that Other North American capacity revenues were generated by your Kendall Operation, which had a long-term tolling agreement but you do not quantify the impact of these agreements. A more in-depth quantification and discussion of the impact of these items you mention will allow the reader to more fully understand your operations. For additional guidance, refer to Item 303(a)(3) of Regulation S-K and SEC Release 33-8350.

In accordance with the Staff’s comments, NRG will provide a more detailed discussion, by reportable segment, for each component of revenues from majority-owned operations in future filings. We recognize our responsibility to provide a more detailed discussion and, as such, included a table at the beginning of Results of Operation at page 53 of our Form-10-K. This table, which included segment detail, was set forth in our Form 10-K to facilitate our detailed discussion in future filings.

Cost of Majority-Owned Operations

Reorganized NRG, page 56

2.	Throughout this section, you refer to various types of costs that make up and contribute to both the cost of energy, operating expenses and also general,

Mr. H. Christopher Owings
May 6, 2005

administrative and development costs for the reported periods. In future filings, in addition to this information please provide an explanation as to the positive and negative factors that impacted those costs. Additionally, rather than using the terms “primarily” or “were largely driven by” in describing changes, to the extent practicable quantify the amount of the change from year to year that is attributable to the primary source you identify. See Item 303(a) of Regulation S-K and Financial Reporting Codification 501.04. In addition to quantifying the dollar effect of the various contributing factors, ensure that you describe the significant developments in the marketplace or at your company that led to the changes.

In accordance with the Staff’s comments, in future filings, NRG will provide explanations as to the positive and negative factors that impacted costs that make up and contribute to the cost of energy, operating expenses and general, administrative and development costs for the reported period. Further, to the extent practicable, we will quantify the amount of the change from year to year that is attributable to the source we identify. We will also describe the significant developments in the marketplace or at the company that led to the changes.

Liquidity and Capital Resources

Sources of Funds, page 81

You indicate that a principal source of liquidity for future operations and capital expenditures are proceeds from the sale of certain assets and businesses. Conversely, on page 82 you indicate that the Amended Credit Facility and the indenture governing the notes place restrictions on the use of any proceeds you may receive from certain asset sales. Please explain and also clarify your disclosures in future filings.

		Under our Amended Credit Agreement and our indenture, net cash proceeds from the sale of certain collateral is subject to mandatory prepayment provisions whereby we are obligated to offer to prepay a portion of the term loan or reduce a portion of the funded letter of credit, in the case of the Amended Credit Agreement, or offer to repurchase notes, in the case of the indenture, subject to the acceptance of individual lenders and noteholders.

		We do not expect that these provisions of the Amended Credit Agreement and the indenture will limit our liquidity to the extent that our ability to conduct business is hampered. We will include this clarification in our future filings.

Contractual Obligations and Commercial Commitments, page 86

4.	Please revise future filings to include other long-term liabilities reflected in your balance sheet as required by Item 303(a)(5) of Regulation S-K or tell us why you

Mr. H. Christopher Owings
May 6, 2005

exclude such amounts from the table. Additionally, to the extent material, please include cash requirements for amounts to be funded to cover post-employment, including retirement, benefits in the table or a related footnote to the table.

The majority of the balance of other long-term liabilities, as of December 31, 2004, consists of out-of-the-money contracts valued at Fresh Start. As this is a non-cash liability, we did not include this in the table. In accordance with the Staff’s comments, NRG will revise future filings to include other long-term liabilities reflected in our balance sheet as required by Item 303(a)(5) of Regulation S-K or we will note why we exclude such amount from the table, and to the extent material, we will include cash requirements for amounts to be funded to cover post-employment, including retirement, benefits in the table or a related footnote to the table.

Critical Accounting Policies

Revenue Recognition and Uncollectible Receivables, page 91

You indicate that in certain markets you record sale and purchase transactions with Independent System Operators on a net basis. Please tell us the GAAP literature you relied upon for your accounting treatment, and specifically how you applied it to your fact pattern. Finally, please tell us how your accounting treatment compares to others in your industry.

		The accounting guidance relied upon in our reporting of certain load-following contracts is EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and ‘Not Held For Trading Purposes’ as Defined in Issue No. 02-3”.

		The following describes how load-following contracts are conducted:

		1) We contract to sell power at a set price to another company,

		2) We purchase power from the ISO at the spot market price,

		3) The ISO delivers power to the counterparty on our behalf, and

		4) The ISO invoices us for the power and delivery services (the ISO can potentially facilitate net settlement).

		Per EITF 02-3, and consequently EITF 03-11, when the load-following contracts are concluded on a net payment basis with the various ISO’s, the net basis presentation is used. Furthermore, it is industry practice to use the net basis presentation.

		Industry practice: Following the adoption of EITF 02-3, the industry conformed to the net reporting presentation in their income statements. There are many types of trading activities within the industry, but primarily, those that have been

Mr. H. Christopher Owings
May 6, 2005

settled in payment on a net basis, are being presented net in the income statement.

Consolidated Financial Statements

Consolidated Balance Sheets, page 105

6.	We read your disclosure in Note 2 as to the nature of the restricted cash on your balance sheet and we are unclear as to why you believe that the restricted cash should be classified as current instead of long-term on your balance sheet.

The vast majority of our restricted cash balances (approximately $97 million or 86% of the total) are restricted in use as a result of various project financings. In all cases, the cash turns over within 12 months, which is why we classify this restricted cash as a current asset. For example, all revenue derived from the plants financed by our Peakers Finance Co. debt is required to be deposited in a restricted cash account. The debt agreements contain a waterfall which provides the order by which these facilities can pay operating and maintenance costs, debt service, etc. Costs are paid on a monthly basis and the debt service is paid annually. The remaining restricted cash balances relate to restrictions as a result of operational requirements which are also expected to lapse in the next 12 months. In future filings we will provide additional disclosure within our accounting policies note that will describe the classification of our restricted cash balance.

Tell us and disclose the nature of the amounts included in the “other” categories within both current and other liabilities. We noted certain items throughout the filing that you indicate as being included in these line items; however, it is unclear as to whether or not additional amounts should be separately disclosed. If those amounts meet the materiality threshold – 5% of total current liabilities and 5% of total liabilities for non-current liabilities – in Rule 5-02(20) and (24) of Regulation S-X please disclose such amounts in future filings.

Other current liabilities include the following amounts:

Mr. H. Christopher Owings
May 6, 2005


	(in millions)
Regulatory-related accruals such as station service (as noted in Note 27), our Connecticut RMR tracker and a payment due to ISO-NE	$	51.5

FAS-146 accrual as noted in Note 8		6.4

Accrued expenses such as legal, audit, consulting, environmental, etc.		37.5

Fuel-related accruals		35.0

Other		22.1


Total Other Current Liabilities	$	152.5


Total Current Liabilities per Consolidated Balance Sheet	$	1,087.9
5% of Total Current Liabilities	$	54.4

		No individual amount noted above exceeds 5% of total current liabilities (or $54 million) as of December 31, 2004, however, we agree that given the size and the many types of items contained in the “Other current liabilities” account, that more explanation is appropriate. In future filings, we will name the line item “Accrued Expenses and Other Liabilities” to clarify that accrued expenses are included therein. Additionally, in future filings, we will disclose in a footnote an explanation of the types and amounts that comprise this total if it is material.

		Other non-current liabilities comprise the following:


	(in millions)
Out-of-market contracts established at Fresh Start, net of accumulated amortization	$	318.7

Asset Retirement Obligation (ARO) as noted in Note 9		32.3

Financial Guarantees		15.0

Environmental Remediation Liabilities as noted in Note 27		5.5

Other		18.2



Total Other Non-Current Liabilities	$	389.7


Total Liabilities per Consolidated Balance Sheet	$	5,131.8
5% of Total Liabilities	$	256.6

The out-of-market contracts are greater than 5% of total liabilities ($256 million). We agree that, in accordance with Rule 5-02(20) and (24) of

Mr. H. Christopher Owings
May 6, 2005

Regulation S-X, these amounts should be disclosed as a separate line item on the face of the Consolidated Balance Sheet. We will revise our future filings accordingly and provide further explanation regarding the nature of this liability.

Notes to Consolidated Financial Statements

Note 2 – Summary of Significant Accounting Policies

Principles of Consolidation and Basis of Presentation, page 110

Please tell us more about the impact the adoption of FIN 46(R) had on your consolidated financial position and results of operations. Your disclosure that “the nature of the operations consolidated consisted of hydropower facilities on the East Coast” is unclear. If you are stating that the adoption lead to the consolidation of certain hydropower facilities that were not previously consolidated please clarify and quantify the impact for us and clarify your disclosures in future filings. Please consider the need for incremental disclosure consistent with paragraph 23 of FIN 46(R).

		Due to the adoption of FIN 46(R) at Fresh Start, NRG first implemented the consolidation of two entities which were previously accounted for as equity investments per APB No. 18. The following tables outline the impact to NRG in a condensed format:

		Condensed impact of newly consolidated entities to the Statement of Operations:


			For the Period
	Year Ended		December 6 -
	December 31,		December 31,
	2004		2003
	(In thousands)
Increase in operating revenues	$	13,542	$	1,252
Increase in costs and expenses		9,511		880
Increase in minority interest in earnings		1,029		135

Decrease in equity earnings	$	3,002	$	237

Condensed impact of newly consolidated entities to the Balance sheet:


	As of			As of
	December 31,			December 31,
	2004			2003
	(In thousands)
Increase in current assets	$	12,812		$	6,398
Increase in noncurrent assets (excluding investment in projects)		45,884			48,677
Decrease in investment in projects		(6,855	)		(4,665	)

Total increase to assets	$	51,841		$	50,411


Increase in current liabilities	$	1,549		$	1,270
Increase in noncurrent liabilities		47,028			46,688
Increase in minority interest		3,264			2,453

Total liabilities and minorities’ interest	$	51,841		$	50,411

Mr. H. Christopher Owings
May 6, 2005

We have considered the need for incremental disclosure per paragraph 23 of FIN 46(R) and have concluded that NRG complies with the exclusion for such disclosure based on the fact that the primary beneficiary, NRG, also holds a majority voting interest. In future filings, we will clearly state that the impact of the consolidation is not material to the balance sheet and results of operations, if applicable.

9.	Please tell us how you determined that your investment in West Coast Power, LLC, did not require consolidation under FIN 46(R). We note that the other 50% owner of West Coast Power, LLC does not consolidate the entity.

As we noted above, NRG implemented FIN 46(R) as of Fresh Start. NRG analyzed whether West Coast Power LLC (WCP) should be considered a variable interest entity and subject to consolidation per the guidance in paragraph 5 of FIN 46(R). NRG concluded that WCP is not a variable interest entity and as such should not be consolidated. Our analysis/decision tree is as follows:

FIN 46(R) Analysis:
1. Paragraph 5(a)

	a.	Is there sufficient equity at risk at WCP? – Yes

	b.	Has entity demonstrated its ability to finance activity without additional support? – Yes

		As such, the conditions in paragraph a are not applicable to WCP, therefore we must continue our analysis per paragraphs 5(b)(1) and 5(c).

	2.	Paragraphs 5(b)(1) and 5(c)

Do the equity owners (which include NRG) as a group lack decision making abilities at WCP? – No

Are voting rights of some investors not proportional to their obligations? – No

	b.	Do the equity owners (which include NRG) as a group lack the obligation for losses of WCP? – No

	c.	Do the equity owners (which include NRG) as a group lack the rights to returns of WCP? – No

		The conditions in paragraphs b and c are not applicable to WCP.

		Based on the above criteria, NRG concluded that West Coast Power LLC is not a variable interest entity and thus FIN 46(R) does not require NRG to consolidate WCP’s results with its own.

		Furthermore, we have also evaluated whether the guidance of EITF 96-16 is applicable to NRG to require the consolidation of WCP. Due to the fact that NRG

Mr. H. Christopher Owings
May 6, 2005

		and the other 50% owner have:

		1. 50/50 voting interests

		2. Operational and financial rights in WCP that were designed to be equal in nature

		We again concluded that the investment in WCP should be accounted for per APB 18, per the equity method. This conclusion is also consistent with the proposed EITF 04-5 as well as the proposed amendment thereof to EITF 96-16.

Note 13 – Investments Accounted for the Equity Method

West Coast Power LLC Summarized Financial Information, page 141

10.

You indicate that the operating revenues for West Coast Power for the year ended December 31, 2004 are $1,334,000. However, the operating revenues for the same period in the audited financial statements of West Coast Power LLC included in Exhibit 99.1 appear to be $725,626,000. We assume that you intended to disclose within Note 13 that the amounts are in millions instead of thousands, implying that the operating revenues are $1,334,000,000. Furthermore, if the difference between the $1,334,000,000 and the $725,626,000 was the result of a typographical error please confirm that to us and revise future filings accordingly to ensure consistency between the audited financial statements of West Coast Power and the summarized financial information that you provide in your financial statements, otherwise please explain why the amounts do not agree.

As you noted, the operating revenues contained in our disclosure in Note 13 for our 50% equity owned investment, West Coast Power LLC, is incorrect. The revenues should be $725,626,000. You are also correct in that the amounts in the tables under “Results of Operations” and “Financial Position” in Note 13 should be in “millions” instead of “thousands”. We will revise our future filings and ensure that they will be consistent between the audited financial statements of West Coast Power LLC and the summarized financial information contained in our footnote disclosure.

Note 18 – Debt and Capital Leases

Project Financings

Itiquira Energetica S.A., page 156

11.

You indicate Eletrobras owns preferred shares in Itiquira but it is unclear as to who or what Eletrobras is and what relationship they have to Itiquira. If Eletrobras and Unibanco are different names for the same entity please clarify. Additionally, please clarify for us why the preferred shares are recorded as debt under US GAAP. If the preferred shares are redeemable for cash at the option of the holder then confirm our understanding, otherwise advise of your accounting.

Mr. H. Christopher Owings
May 6, 2005

		Eletrobras and Unibanco are different entities. Eletrobras is Brazil’s main power generation and transmission company and is the holder of the Itiquira preferred shares. Unibanco is a large private sector bank in Brazil and is a lender under the long-term financing arrangement.

		The preferred shares held by Eletrobras contain a fixed and mandatory redemption feature. Under FAS 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities & Equity” paragraph 9, the preferred shares are deemed to be a mandatorily redeemable financial instrument, and are thus considered a long term liability for US GAAP purposes. Similar to the cumulative dividends discussed on page 156 of the Form 10-K, the redemptions are payable when Itiquira has sufficient retained profits or reserves.

		In future filings, we will expand the footnote to ensure that the reader fully understands the accounting treatment for these preferred shares.

Schkopau, page 165

12.

Tell us the US GAAP basis for recording the Schkopau debt obligations as capital leases.

		Our subsidiary, Saale Energie GmbH (SEG), entered into two agreements which qualify for treatment as capital lease agreements in accordance with FAS 13 as the agreements are for a term that surpasses 75% of the economic life of the power plant. This conclusion is further supported by the guidance of Emerging Issues Task Force No. 01-8, “Determining Whether an Arrangement Contains a Lease”.

		The agreements are (a) the “Agreement on the Surrender of the Use and Benefit” (U&B Contract) between SEG and Kraftwerke Schkopau GbR, (Schkopau); and (b) the Power Supply Contract (PPA) between SEG and Vattenfall Europe A.G. (VEG). Both contracts transfer substantially all of the benefits and risks of SEG’s ownership interest in its share of power generation in the power plant from Schkopau to VEG. SEG owns 41.9% of the Schkopau plant, which issued debt pursuant to multiple facilities to finance a construction project. Because Schkopau is not permitted to retain funds in its own account (and therefore cannot pay its debt service), it receives funds from SEG and the other owner on a pro rata basis to meet debt service payments as they become due. The funds received are from the electricity sales under the power supply contract.

		The PPA is not simply a service contract, but rather a lease contract, because SEG sells 100% of the capacity in its share of the power plant over 25 years (which is more than 83% of the useful life of the power

Mr. H. Christopher Owings
May 6, 2005

		plant) to VEG. The U&B Contract is accounted for as a long-term lease obligation in the consolidated financial statements. The PPA is accounted for as a direct financing lease with a note receivable in the consolidated financial statements. NRG has recognized a nonrecourse capital lease on the consolidated balance sheet in the amount of $303.8 million and $342.5 million at December 31, 2004 and 2003, respectively. The capital lease obligation is recorded at the net present value of the minimum lease obligation payable over the lease’s remaining period of 17 years (See Note 18 of the Form 10-K). In addition, a direct financing lease was recorded in notes receivable in the amount of approximately $461.8 million and $451.4 million as of December 31, 2004 and 2003, respectively (see Note 11 of the Form 10-K).

		The description, as noted above, can be found in Exhibit 99.9 of our Form 10-K/A filed on November 3, 2004. We agree, however, that in future filings, our disclosure contained in our debt footnote should be clarified and expanded to ensure that the reader fully understands the accounting treatment for these contracts that gives rise to capital lease treatment.

Note 22 – Earnings Per Share, page 165

13.

You indicate that the deferred stock units are considered outstanding upon the grant date on a weighted average basis for computing basic earnings per share however it appears you have not considered them in your basic earnings per share calculation. If your disclosure is incorrect as a result of a typographical error and you intended to state that they are considered in your diluted earnings per share calculation then please revise your disclosure in future filings. If you believe it is appropriate to include the deferred stock units in your diluted earnings per share calculation please tell us why.

		The disclosure is incorrect as a result of a typographical error, and will be revised in future filings.

		We believe it is appropriate to include the deferred stock units (DSU’s) in our diluted earnings per share based on their terms and conditions as found in NRG’s Long-Term Incentive Plan (see Exhibit 4 to the Form S-8 filed on March 29, 2004), and the guidance provided in FAS 128, “Earnings per Share”, paragraph 30(b), which states the following:

“If all necessary conditions have not been satisfied by the end of the period, the number of contingently issuable shares included in diluted EPS shall be based on the number of shares if any that would be issuable if the end of the reporting period were the end of the contingency period and if the result would be dilutive. Those contingently issuable shares shall be included in the denominator of diluted EPS as of the beginning of the period (or as of the date

Mr. H. Christopher Owings
May 6, 2005

of the contingent stock agreement, if later).”

As defined in NRG Energy, Inc.’s Long-Term Incentive Plan, the DSU’s are only issuable when certain conditions exist, and these conditions did not exist as of December 31, 2004. As such, the DSU’s are considered contingently issuable shares for purposes of paragraph 30(b) of FAS 128, and should only be included in the calculation of diluted EPS.

Note 29 – Guarantees and Other Contingent Liabilities

Other types of guarantees, page 191

14.

You indicate that the maximum quantifiable liability under the environmental guarantees is approximately $65.9 million, most of which is a guarantee for plant removal and site remediation obligations at your Flinders facility. In light of this, please tell us whether the plant removal and site remediation obligations of your Flinders facilities are included in your asset retirement obligation balance as of December 31, 2004 and if so tell us the amount. If no asset retirement obligation has been recorded please tell us why.

The plant removal and site remediation obligations for our Flinders facility included in our asset retirement obligation balance as of December 31, 2004 are $14 million, and this balance will accrete until the estimated date of remediation.

Exhibit 99.1 – West Coast Power LLC

Note 2 – Accounting Policies

Revenue Recognition, page 11

15.

You indicate that you recognize revenues identified as being subject to future resolution as discussed above at “Allowance for Doubtful Account.” However, the referenced disclosure does not appear to contain a discussion of your revenue recognition policies. Please supplementally explain the nature and amount of revenues recognized that are subject to further resolution and how you support your accounting. Please refer to SAB Topic 13A.

The amount of revenues recognized that are subject to further resolution in 2004, 2003 and 2002 are zero. During the California electricity crisis of 2000 and 2001, West Coast Power LLC (WCP) generated and delivered electricity to participants in the California wholesale electricity markets. These sales did not meet certain of the criteria outlined in SAB Topic 13A as contracts specifying the terms of the transactions had been executed, the electricity had been produced and delivered, the prices were fixed, however the pricing and ultimate collection by was being disputed

Mr. H. Christopher Owings
May 6, 2005

by numerous parties in and outside of the marketplace. As a result, the revenue line of WCP’s income statement at the time was presented broadly, showing both the gross amount of disputed sales and the gross associated reserve of revenues, negating recognition in income. This resulted in the recognition of a receivable balance and an associated reserve of those receivables. WCP believed that at the time this better presented to a reader of its financial statements the magnitude of the sales for which there was no net income recorded. Subsequently in 2004, as discussed in Note 9 to WCP’s financial statements, WCP entered into a comprehensive settlement agreement with various parties that included WCP forgoing its right to pursue collection of the disputed sales. In future filings, WCP will provide additional disclosure within the revenue recognition footnote that will describe their revenue recognition policy.

Note 5 – Derivatives and Hedging, page 12

16.

You indicate that the values of the fair value hedges as well as the corresponding value of the hedged risk at December 31, 2004 are zero. In light of this, we are unclear as to the nature of the assets and liabilities from risk-management activities recorded on your balance sheet as of December 31, 2004. Please explain.

In addition to the fair value hedges discussed in Note 5 to WCP’s financial statements, which expired on December 31, 2004, WCP previously had entered into cash flow hedges of both power and gas to hedge the variability of future cash flows associated with the sale of electricity and the purchase of natural gas. In December 2004, WCP elected to designate all of its generation units as RMR condition II, under which WCP will receive only a fee for the generation of power and reimbursement of costs in 2005. Therefore, the anticipated sale of power and purchase of gas at variable future market prices, which was being hedged, ceased. As a result, these cash flow hedges no longer qualified as hedges under SFAS 133, as amended, and changes in fair value recorded in OCI were recognized in earnings. Any future changes will be recognized in income as they occur. In future filings, WCP will provide additional disclosure within its derivative footnote that will describe its assets and liabilities from risk management activities.

Note 33 – Condensed Consolidated Financial Information, page 195

17.

Please confirm to us, if true, and revise future filings to indicate that the guarantees are joint and several and that each guarantor is 100% owned. Otherwise, tell us how your disclosure complies with Rule 3-10 of Regulation S-X.

We confirm that each guarantor subsidiary listed in Note 33 to the Form 10-K is directly or indirectly 100% owned by NRG Energy, Inc. Furthermore, we confirm that the guarantees issued by the guarantor subsidiaries are joint and several, pursuant to the Guarantee and Collateral Agreement dated as of December 23, 2003 as amended and restated as of December 24, 2004 made by NRG Energy, Inc. and the guarantor subsidiaries in favor of Deutsche Bank Trust Company Americas, Credit

Mr. H. Christopher Owings
May 6, 2005

Suisse First Boston and Law Debenture Trust Company of New York (See Exhibit 10.26 to the Form 10-K).

* * * * * *

Mr. H. Christopher Owings
May 6, 2005

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 Tanuja Dehne, Assistant General Counsel, at (609) 524-4592 if you have questions regarding our responses or related matters, or me at (609) 524-4591 with any other questions.

				Sincerely,

				/s/ TIMOTHY W. J. O’BRIEN

				Timothy W. J. O’Brien Vice President, General Counsel and Secretary


cc:	David Mittelman, Legal Branch Chief, Securities and Exchange Commission George Ohsiek, Securities and Exchange Commission David DiGiacomo, Securities and Exchange Commission Matthew Benson, Staff Attorney, Securities and Exchange Commission Robert C. Flexon, NRG Energy, Inc. Michael P. Rogan, Esq., Skadden, Arps, Slate, Meagher & Flom LLP