NRG Energy, Inc.
		211 Carnegie Center
		Princeton, NJ 08540
		Phone: 609.524.4500
		Fax: 609.524.4501

October 19, 2009

Securities and Exchange Commission
Division of Corporation Finance
Mail Stop 3561
100 F Street, N.E.
Washington, D.C. 20549
Attn: Christopher Chase, Attorney-Advisor

RE:		NRG Energy, Inc. Form l0-K for the year ended December 31, 2008 Filed February 12, 2009 Amendment No. 1 to Form 10-K for the year ended December 31, 2008 Filed April 30, 2009 Form 10-Q for Quarterly Period ended March 31, 2009 Filed April 30, 2009 Form 10-Q for Quarterly Period ended June 30, 2009 Filed July 30, 2009 File No. 001-15891

Dear Mr. Chase:

     We hereby respond to the comments made by the Staff in your letter dated September 30, 2009 relating to the above referenced filings of NRG Energy, Inc. (“NRG” or the “Company”). Since the Company and management are in possession of all the facts relating to the Company’s disclosure, 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:

Form 10-K for the Fiscal Year Ended December 31, 2008

Item 6 — Selected Financial Data, page 67

1.

Explain to us and disclose in a footnote to the table how you calculated your liquidity position as of December 31, 2008. In addition, explain your basis for including counterparty deposits in your liquidity position when you disclose management intends to limit the use of these funds.

     Response: Our liquidity position is determined as disclosed in Item 7 of the 2008 Form 10-K, on page 110 under Liquidity and Capital Resources — Liquidity Position. We acknowledge the

Staff’s comment and in future filings commencing with our 2009 Form 10-K, we will expand footnote (a) to the Selected Financial Data table to add a cross-reference to the Liquidity and Capital Resources disclosure.

     We include “funds deposited by counterparties” in our liquidity position because they are available to settle the related current liability for “cash collateral received in support of energy risk management activities.” In the balance sheet data disclosed in Item 6, “funds deposited by counterparties” are included within current assets and “cash collateral received in support of energy risk management activities” are included within current liabilities. In future filings, commencing with our 2009 Form 10-K, we will expand footnote (a) to the Selected Financial Data table to explain that the funds deposited by counterparties are intended to be limited for repayment of the related current liability.

     In future filings, our footnote (a) will read substantially similar to the following (changes are italicized):

(a)

Liquidity position is determined as disclosed in Item 7, Liquidity and Capital Resources, Liquidity Position, and includes Funds deposited by counterparties of $754 million as of December 31, 2008, which represents cash held as collateral from hedge counterparties in support of energy risk management activities. It is the Company’s intention as of December 31, 2008 to limit the use of these funds for repayment of the related current liability for collateral received in support of energy risk management activities.

2.

With a view toward increased transparency, revise the operating revenue table to present revenue from trading activities separately. We understand this information could be determinable from other disclosures within your document.

     Response: Currently, we disclose in tabular form the unrealized results of our trading in Item 7 — Management Discussion and Analysis (“MD & A”) under Consolidated Results of Operations. Commencing with our third quarter 2009 Form 10-Q, we will expand such MD&A disclosure to show realized and unrealized trading results. Historically, our trading results are immaterial to our operating revenue. For example, our 2008 trading result was approximately 2% of total operating revenue. We believe that the above expanded MD&A disclosure would provide the increased transparency that you are requesting for the reader of the financial statements.

Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 69

Business Environment, page 72

3.

Please explain to us and revise to summarize the changes in power prices for each major market where you operate. We understand that you hedge your revenue and fuel costs, however, we assume significant increases in power price volatility impact the cost of hedging. Furthermore, power prices directly impact the value of your plants.

     Response: Under Other Factors on page 73, we currently disclose a number of general factors that influence the level and volatility of prices for energy commodities and related derivative products. Additionally, we currently disclose average on-peak market power prices ($/MWh) in our regional discussions of Results of Operations beginning on page 92. We acknowledge the Staff’s comment and in future filings, commencing with our 2009 Form 10-K, we will enhance our discussion of the business environment by adding additional disclosure substantially similar to the following:

Energy Prices — The price of power is a key determinant of the profitability of our generation portfolio. In 2008, power prices were higher than in 2007, but extremely volatile. Higher volatility translates into higher hedging costs and also impacts the fair value of our generation assets. The following table summarizes average on-peak power prices for each of the major markets in which we operate, for the years ended December 31, 2008 and 2007:

Avg On Peak Power Price ($/MWh)
		2008				2007
Texas		$	96.53			$	62.00
Northeast		$	91.70			$	76.37
South Central		$	71.25			$	59.62
West		$	82.62			$	66.52

Results of Operations, page 75

4.

Explain to us the factors which necessitated the need for the $23 million impairment charge to restructure the distressed investments in commercial paper and revise your disclosure accordingly.

     Response — The impairment charge of $23 million resulted from a change in our fair value assessment as a result of a public auction of the assets in the structured investment vehicle underlying our investment in available-for-sale debt securities. The auction was the first observable market participation since the structured investment vehicle became illiquid in late 2007. The impairment was deemed to be other than temporary in accordance with the guidance in ASC 320-10-35 — Investments — Debt and Equity — Overall - Subsequent Measurement (FSP FAS 115-1/124-1: The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments).

     We acknowledge the Staff’s comment and in future filings, commencing with our 2009 Form 10-K, we will expand the disclosure under Other Income, Net (see page 81 of the 2008 Form 10-K) to read substantially similar to the following (changes are italicized):

     NRG’s other income, net decreased by $38 million for 2008 compared to the same period in 2007. The Company recorded a further $23 million impairment charge in 2008 to restructure distressed investments in commercial paper, for which an $11 million impairment charge was taken in the fourth quarter of 2007. The impairment charge resulted from a change in our fair value assessment as a result of a public auction of the assets in the structured investment vehicle holding the investments; this auction was the first observable market participation since the structured investment vehicle became illiquid in 2007. This 2008 impairment charge, along with cash receipts of $2 million, reduced the carrying value of the commercial paper to $7 million. In addition, the 2008 results reflect reduced interest income of $25 million from lower market interest rates on cash deposits.

Liquidity and Capital Resources, page 110

5.

Revise your disclosure to discuss the affect on you of a downgrade in your credit ratings, including for example, the impact on your energy contracts that require the posting of collateral or allow for early counterparty termination.

     Response: Our current credit rating is below investment grade at B1/BB-, and therefore many counterparties have not extended unsecured credit to us. As a result, to the extent credit has been extended to us and we suffer a downgrade event, the effect would be minimal. We began

disclosing credit risk related contingent features in the first quarter 2009. We acknowledge the Staff’s comment and in future filings, we will continue to provide disclosure substantially similar to that on page 24 of our Form 10Q for the period ended June 30, 2009, which states the following:

     Certain of the Company’s hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements. Other agreements contain provisions that require the Company to post additional collateral if there was a one notch downgrade in the Company’s credit rating. There are certain marginable agreements where NRG has a net liability position but the counterparty has not called for the collateral due, which was approximately $87 million as of June 30, 2009. The aggregate fair value of all derivative instruments with credit rating contingent features that are in a net liability position as of June 30, 2009 was $54 million. The aggregate fair value of all derivative instruments that have adequate assurance clauses that are in a net liability position as of June 30, 2009 was $18 million.

     Under the CSRA, Merrill Lynch provides guarantees and the posting of collateral to the Company’s counterparties in supply transactions for the Company’s retail energy business. In the event of any unwind of the CSRA with Merrill Lynch, NRG will have to post collateral for any existing out-of-money hedging transactions that support the retail operation. The level of collateral posting would be determined based on the timing of the unwind, and the volume and pricing of the commodity hedging agreements. As of June 30, 2009, Merrill Lynch was providing $630 million in credit support to various counterparties.

6.

We note the separate classification on the balance sheet of funds deposited by counterparties totaling $754 million as of December 31, 2008. Please disclose any material restrictions with regard to the use of these funds on your liquidity.

     Response: On page 110 and under Footnote 2 on page 143 of our 2008 Form 10-K, Funds Deposited by Counterparties, we currently disclose the Company’s intention to limit the use of these funds for refund to the hedge counterparties. We acknowledge the Staff’s comment and in future filings, commencing with our third quarter 2009 Form 10-Q, we will clarify that these amounts are segregated into separate accounts that are not contractually restricted but, based on the Company’s intention, are not available for the payment of NRG’s general corporate obligations. The funds represent the amounts that are held by NRG as a result of collateral posting obligations from our counterparties due to positions in our hedging program. Over time these funds will be returned to such counterparties and are not available to net against other NRG collateral cash needs.

Contractual Obligations and Commercial Commitments, page 118

7.

Explain if your other non-current liabilities on the balance sheet are reflected in the recorded contractual obligations table, if not, please revise.

     Response: NRG’s other non-current liabilities were $392 million as of December 31, 2008. The majority of the balance in other non-current liabilities, as of December 31, 2008, consists of ASC 740 (FIN 48) liabilities for uncertain tax positions (including related interest payable) and asset retirement obligations. We did not include the liabilities for uncertain tax positions in the table because we are unable to reasonably estimate the timing of these liabilities and related interest payments as the result of uncertainties in the timing of the effective settlement of tax positions. For the same reason, we did not include asset retirement obligations because we are

unable to reasonably estimate the timing of effective settlement. In note (b) of the Contractual Cash Obligations table on page 118, we disclosed that the non-current liabilities for uncertain tax positions are excluded from the table. In future filings commencing with our 2009 Form 10-K, we will revise this note to indicate that the table does not include asset retirement obligations which are discussed in detail in Note 2 — Summary of Significant Accounting Policies as well as other non-current liabilities not directly derived from contracts or other agreements.

     We acknowledge the Staff’s comment and in future filings, we will ensure that our disclosures include other non-current liabilities reflected in our balance sheet as required by Item 303 (a) (5) of Regulation S-K or we will note why we excluded such amounts from the table, to the extent material.

Critical Accounting Policies and Estimates, page 121

8.

Please explain to us if you considered providing critical accounting policies related to your postretirement and other benefit obligations, and your nuclear decommissioning trust liability. To the extent you decide to enhance your critical accounting policy discussion for these items, please include a sensitivity analysis of the significant assumptions or any other quantitative information to the extent that is material to the understanding of the assumptions. In this regard, you should address the questions that arise once the critical accounting estimate or assumption has been identified, by analyzing, to the extent material, such factors as to how you arrived at the estimate, how accurate the estimate/assumption has been in the past, how much the estimate/assumption has changed in the past, and whether the estimate/assumption is reasonably likely to change in the future. For additional guidance, refer to Item 303 of Regulation S-K as well as section five of the Commission’s Interpretative Release on Management’s Discussion and Analysis of Financial Condition and Results of Operation which is located on our website at: http://www.sec.gov/rules/interp/33-8350.htm.

     Response: NRG identifies its most critical accounting policies as those that are most pervasive and important to portrayal of the Company’s financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates that are inherently uncertain. We considered providing critical accounting policies related to our postretirement and other benefit obligations, and our nuclear decommissioning trust liability, and concluded they do not meet these criteria to disclose as a critical accounting policy.

     Post-retirement and other benefit obligations

     We provide detailed information on our benefit plans and other postretirement benefits in Note 12 — Benefit Plans and Other Postretirement Benefits to our audited financial statements in the 2008 Form 10-K. For the year ended December 31, 2008, our net periodic benefit cost was $34 million, or 3.3% of our income from continuing operations, and we made employer contributions of $106 million toward defined benefit plans. At December 31, 2008, our excess of obligation over plan assets was $262 million, or 1.5% of our total liabilities. We considered the magnitude of these amounts, as well as the availability of independent actuary advice that facilitated managements’ judgments, and concluded that the criteria for disclosure as a critical accounting policy were not met.

     Nuclear decommissioning trust liability

     As discussed in Comment 6 in our letter to the Staff dated May 14, 2007 and in Comment #20 hereinafter, the original utility owners of our 44% interest in STP are authorized by the Public Utility Commission of Texas (“PUCT”) to collect decommissioning funds from their ratepayers to cover decommissioning costs on behalf of NRG. Nuclear Regulatory Commission (“NRC”)

requirements determine the decommissioning cost estimate which is the minimum required level of funding. In the event that funds from the ratepayers that accumulate in the nuclear decommissioning trust are ultimately determined to be inadequate to decommission the STP facilities, the utilities will be required to collect through rate base all additional amounts, with no obligation from NRG, provided that NRG has complied with PUCT rules and regulations regarding decommissioning trusts. Following completion of the decommissioning, if surplus funds remain in the decommissioning trusts, any excess will be refunded to the respective ratepayers of the utilities. At December 31, 2008, the nuclear decommissioning trust fund balance was $303 million, or 1.2% of NRG’s total assets, and the nuclear decommissioning asset retirement obligation was $284 million, or 1.6% of NRG’s total liabilities.

     We account for our nuclear decommissioning activities in accordance with ASC 980 - Regulated Operations (SFAS 71 — Accounting for the Effects of Certain Types of Regulation) because these activities are subject to approval by an independent third party regulator, with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since we are in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all movements in the Nuclear Decommissioning Trust Fund and related asset retirement obligations are offset by entries to the Nuclear Decommissioning Trust Liability to the ratepayers, and no amounts are recorded in our income statement or to our accumulated other comprehensive income. Since there is no impact on NRG’s financial position and liquidity, we concluded that the criteria for disclosure as a critical accounting policy were not met.

9.

Revise your disclosure to include a sensitivity analysis of the significant assumptions with respect to fair valuing your derivative financial instruments. In this regard, we note your disclosure on page 120 that future market prices could vary from those used in recording assets and liabilities from energy trading and marketing activities and such variations could be material. More context could be provided by disclosing and quantifying the impact that could result given the range of reasonably likely outcomes of, for example, a percentage increase or decrease in future market prices.

     Response: We acknowledge the Staff’s comment. As the natural gas price is a key driver of the fair value of our derivative assets and liabilities, in future filings, commencing with our third quarter 2009 Form 10-Q, we will expand our disclosures to provide sensitivity of a $1 change in natural gas price on the fair value of our net derivative assets or liabilities as of the period-end.

Item 7A — Quantitative and Qualitative Disclosure about Market Risk, page 126

Credit Risk, page 128

10.

You indicate on page 129 that you have heightened your management and mitigation of counterparty credit risk by using credit limits, netting agreements, collateral thresholds, volumetric limits and other mitigation measures, where available as a result of the economic downturn experienced in the latter part of 2008. Please revise your disclosure to elaborate upon the steps you have taken to manage your credit exposure.

     Response: We acknowledge the Staff’s comment and in our future filings, commencing with our third quarter 2009 Form 10-Q, we will enhance our disclosure to expand on the steps we have taken to manage our credit exposure. For example, as a result of the economic downturn experienced in the latter part of 2008, we have taken the following steps to mitigate credit exposure:

	a.		Terminated contracts without collateral thresholds;
	b.		Entered into netting agreements with certain counterparties;
	c.		Restricted trading relationships with counterparties where exposure was high or where credit quality of the counterparty had deteriorated.

Item 9A — Controls and Procedures, page 130

Changes in Internal control over Financial Reporting, page 130

11.

We note your indication that, other than as described below, there were no changes in your internal control over financial reporting identified that occurred in the fourth quarter of 2008. Rather than state that there were no changes other than those described below, please state that there were changes that materially affected your internal control over financial reporting and refer readers to the discussion of those changes.

     Response: We acknowledge the Staff’s comment and in future filings, commencing with our third quarter 2009 Form 10-Q, we will state affirmatively, when applicable, that there were changes during the quarter that materially affected our internal control over financial reporting and will refer readers to the discussion of those changes.

Consolidated Balanced Sheets, page 138

12.

We note funds deposited by counterparties were classified as a current asset on your consolidated balance sheets. In this regard, we assume the underlying contracts do not extend beyond one year. If not, please explain in detail why you did not classify a portion of the margin or deposit amounts as a long-term asset to match the classification of the fair value of the related contracts. Please advise, or revise.

     Response: Approximately one-third of the funds deposited by counterparties relate to the portion of underlying hedge contracts that extend beyond one year. We classify unrealized mark-to-market on underlying contracts reflected on the balance sheet as long-term based on their contractual settlement dates because consideration will not transfer prior to those dates. By contrast, cash collateral required from hedge counterparties will vary daily based on market fluctuations, with any excess collateral held then becoming repayable on demand rather than at the settlement date of the underlying hedge contract. Since collateral requirements fluctuate daily and we cannot predict if any collateral will be held for more than 12 months, we have classified both the obligation to return collateral to the hedge counterparties (i.e., $754 million within “cash collateral received in support of energy risk management activities”) and the related asset (i.e., $754 million of “funds deposited by counterparties”) as current, with no net effect on working capital.

Note 2 — Summary of Significant Accounting Policies, page 142
Intangible Assets, page 144

13.

Please explain for us and revise your disclosure to clarify if you perform a lower of cost or market analysis on your purchased emission allowances when reclassified to held-for-sale. In addition, please clarify if the gains on sale of the emission allowances relate solely to amounts transferred to held-for-sale.

     Response: As discussed in NRG’s 2008 Form 10-K, Note 10 — Goodwill and Other Intangibles, pages 169-170, NRG management may authorize the transfer of emission allowances

from its held-for-use emissions bank to intangible assets held-for-sale; these allowances are transferred at weighted average carrying value. NRG also purchases certain emission allowances for resale as part of its asset optimization strategy, which are recorded as held-for-sale at weighted average cost. Emission allowances held-for-sale are not amortized; they are carried at the lower of cost or fair value, and evaluated on a regular basis in accordance with NRG’s asset impairment policy and ASC 360 — Property, Plant and Equipment.

     NRG’s policy is to only sell emission allowances that have either been purchased directly for sale, or authorized by management to be transferred to a held-for-sale account. Any gains or losses upon sale are recognized immediately in the Company’s consolidated statement of operations.

     We acknowledge the Staff’s comment and in future filings, commencing with our 2009 Form 10-K, we will enhance our Intangible Assets Accounting policy by adding language substantially similar to the following: “Emission allowances held-for-sale are not amortized; they are carried at the lower of cost or fair value and reviewed for impairment in accordance with ASC 360.”

14.

Please advise or revise to include an environmental accounting policy footnote. Refer to paragraph 151 of SOP no. 96-1.

     Response — As of December 31, 2008, the Company had approximately $9 million of environmental remediation liabilities recorded on the balance sheet in accordance with ASC 410-30 — Environmental Obligations (SOP 96-1). We did not consider this liability material for disclosure, nor did we believe it reasonably possible that there would be a material change in the near term; hence we omitted disclosure as a significant accounting policy in accordance with ASC 235-10-50 — Notes to Financial Statements — Overall Accounting Policies Disclosure.

     Please note that substantially all of our environmental liabilities result from the normal operations of our long-lived assets and are associated with the retirement of those assets. Accordingly, they fall within the scope of ASC 410-20 — Asset Retirement Obligations (SFAS 143). We disclose our accounting policies for AROs in Note 2 of our 2008 Annual Report on Form 10-K, page 148.

Goodwill, page 145

15.

Please explain to us and summarize how you determine the fair value of your Texas reporting unit. In this regard, please explain if you factor into your analysis hedging strategies that could affect assumptions with regard to revenue growth, margins, and costs in your cash flow projections.

     Response: We performed our annual goodwill impairment assessment using income and market approaches, as summarized more fully on page 125 of our 2008 Form 10-K under Critical Accounting Policies and Estimates. To clarify and expand upon that disclosure, we determined the fair value of our Texas reporting unit using the described income approach, and then applied an overall market approach reasonableness test to reconcile that fair value with NRG’s overall market capitalization. Under the income approach for the three solid-fuel baseload plants that drive a majority of the value in the reporting unit, we applied a discounted cash flow methodology to their long-term budgets in accordance with the guidance in paragraphs B152 and B155 of SFAS 142. These budgets are based on the Company’s views of power and fuel prices, which consider market prices in the near term and the Company’s fundamental view for the longer term as some relevant market prices are illiquid beyond 24 months. Hedging is included

to the extent of contracts already in place. For the remaining gas plants, we applied a market-derived earnings multiple to their aggregate estimated 2008 earnings before interest, taxes, depreciation and amortization, in accordance with the guidance in ASC-350-20-35-24 (paragraph 25 of SFAS 142).

16.

Please provide to us a summary of your Step 1 results from your annual goodwill impairment test and include a comparison of the fair value of your Texas reporting unit to your market capitalization, as represented by NRG Texas, and further explain the underlying reasons for the difference. Lastly, please revise your future critical accounting policy discussion to provide a meaningful sensitivity analysis regarding future possible changes in the more significant assumptions used to determine the fair value of your NRG Texas reporting unit.

     Response: Under Step 1 of our annual goodwill impairment test, we applied the income approach and estimated the fair value of NRG Texas’ invested capital to exceed its carrying value by approximately 25%, primarily driven by our solid fuel baseload plants. To reconcile this fair value with NRG’s market capitalization, we next estimated the market indicated portion represented by NRG Texas, as measured by four different earnings measures, each over three different historical time periods, to be approximately two-thirds of NRG’s overall invested market capitalization. Under this assumption, our Step 1 fair value estimate for NRG Texas implied a significant control premium relative to NRG’s overall market capitalization at December 31, 2008. We believe our stock price was depressed as a result of the general economic climate, the substantial decline in the stock market as a whole, and uncertainty surrounding the Exelon offer. However, we performed sensitivity analysis of NRG’s market capitalization assuming a number of control premium scenarios ranging from no premium in excess of the December 31, 2008 market capitalization (at the low end) to the implied fair value from our Step 1 analysis (at the high end). In all instances, the calculated market values allocable to NRG Texas exceeded the NRG Texas book value, with the worst-case scenario of no premium resulting in a 1% excess, and we concluded that goodwill was not impaired as of December 31, 2008.

     We acknowledge the Staff’s comment and in future filings, commencing with our 2009 Form 10-K which will reflect our next annual goodwill impairment assessment performed each December, we will revise our critical accounting policy discussion to provide sensitivity analysis regarding the more significant assumptions used to determine the fair value of our NRG Texas reporting unit.

Asset Retirement Obligations, page 148

17.

Explain to us the reason for the significant cash flow revision to the asset retirement obligations in 2008 as shown in the asset retirement obligations rollforward table.

     Response: As noted in your comment, the Company’s asset retirement obligation (“ARO”) rollforward table in Note 2 of our 2008 Annual Report on Form 10-K reflects a $41 million decrease in our ARO obligation attributed to “revisions in estimated cash flows.” Approximately $40 million of this decrease relates to a downward revision of our nuclear decommissioning reserve for the South Texas Project nuclear generating facility (“STP”) in which NRG owns a 44% interest.

     The Code of Federal Regulations, Title 10, Part 50, Section 50.75, requires STP to perform up-to-date assessments of its nuclear decommissioning reserves. In addition, PUCT Rule 25.303f(2) mandates that “a study or re-determination of the previous study shall be performed at

least every five years”, therefore requiring STP to perform an update in 2008. This update necessitated revisions to both the timing and amount of the prior undiscounted cash flow estimates, which resulted in downward revision to our ARO liability on a discounted basis. In accordance with ASC 410-20-35 - Asset Retirement Obligations — Subsequent Measurement (FAS 143, par. 15), this downward revision was recognized as a decrease in both our ARO liability and the related asset retirement cost capitalized as part of our fixed assets.

Note 4 — Fair Value of Financial Instruments, page 157
Recurring Fair Value Measurements, page 158

18.

We read your disclosure on page 160 indicating that the majority of your contracts are valued using prices provided by external sources. We also note that the majority of your derivative assets and liabilities were classified as level 2 in your fair value hierarchy. Please explain how you determined these derivative assets and liabilities were appropriately classified as level 2 in your fair value hierarchy. In this regard, to the extent observable data was not present with respect to the derivative instruments valued by the broker, please explain how you concluded level 2 classification was appropriate. Please see paragraph 28 of SFAS no. 157.

     Response: NRG’s derivative instruments consist of energy and interest rate instruments. A significant portion of our energy derivatives are over-the-counter commodities traded through brokers or natural gas instruments traded bi-laterally. Our natural gas commodity transactions are referenced to NYMEX prices and thus we use NYMEX period-end natural gas prices to value such derivatives. For our other energy commodities, we use broker price quotes to value the derivatives. We transact with counterparties through these brokers on a regular basis. We believe that the NYMEX prices and broker quotes are observable inputs within the Level 2 category as defined under either paragraph 48(a) or 48(b) of ASC 820-10-35 (paragraph 28(a) or 28(b) of FAS 157) as follows:

	a.		Quoted prices for similar assets or liabilities in active markets
	b.		Quoted prices for identical or similar assets or liabilities in markets that are not active, that is, markets in which there are few transactions for the asset or liability, the prices are not current, or price quotations vary substantially either over time or among market makers (for example, some brokered markets), or in which little information is released publicly (for example, a principal-to-principal market)
	c.		Inputs other than quoted prices that are observable for the asset or liability (for example, interest rates and yield curves observable at commonly quoted intervals, volatilities, prepayment speeds, loss severities, credit risks, and default rates)
	d.		Inputs that are derived principally from or corroborated by observable market data through correlation or by other means (market-corroborated inputs)

     We consider broker quotes as observable as such data is readily available, regularly distributed, from multiple independent sources, transparent, verifiable and not proprietary. Also, the data is reliable, based on a consensus within a reasonably narrow observable range, provided by sources actively involved in the relevant market, and supported by market transactions.

     We also use other observable data such as interest rates, volatilities and Credit Default Swap spreads to value our derivatives and consider them as a level 2 input as described in ASC 820-10-35-48(c) (FAS 157, paragraph 28(c)).

19.

Please explain to us and expand your disclosure to indicate management’s consideration of the following with regard to the pricing obtained from the external brokers:

	•		Whether the broker is willing and able to trade at the quoted price.
	•		If the broker quotes are based on an active market, or an inactive market.
	•		The extent to which brokers are utilizing a particular model if pricing is not readily available.

     Response: NRG’s use of brokers in various markets facilitates the execution of transactions with counterparties. In a brokered market, these brokers attempt to match buyers with sellers; they do not stand ready to trade for their own account and do not use their own capital to hold an inventory of the items for which they make a market. We obtain price quotes from multiple brokers who regularly facilitate our transactions in order to obtain the best estimate of fair value and to exclude any outliers. Thus we believe that these broker quotes are executable. We do not use third party sources that derive prices based on proprietary models or market surveys.

     In future filings, commencing with our third quarter 2009 Form 10-Q, we will expand our disclosures to note that “a significant portion of the fair value of our derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate our transactions and we believe such price quotes are executable. We do not use third party sources that derive price based on proprietary models or market surveys.” Our revised disclosure will read as follows (changes are italicized):

     A small portion of NRG’s contracts are exchange-traded contracts with readily available quoted market prices. The majority of NRG’s contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company’s prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the Company receives one quote then the mid-point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. A significant portion of the fair value of our derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate our transactions and we believe such price quotes are executable. We do not use third party sources that derive price based on proprietary models or market surveys. The remainder of the assets and liabilities represents contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Contracts valued with prices provided by models and other valuation techniques make up 10% of the total fair value of all derivative contracts. The fair value of each contract is discounted using a risk free interest rate. In addition, the Company applies a credit reserve to reflect credit risk which is calculated based on published default probabilities. To the extent that NRG’s net exposure under a specific master agreement is an asset, the Company is using the counterparty’s default swap rate. If the exposure under a specific master agreement is a liability, the Company is using NRG’s default swap rate. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG’s liabilities or that a market participant would be willing to pay for NRG’s assets. As of June 30, 2009, the credit reserve resulted in a $23 million increase in fair value which is composed of a $1 million loss in OCI and a $24 million gain in derivative revenue and cost of operations.

Note 6 — Nuclear Decommissioning Trust Fund, page 167

20.

In your letter to the Staff dated June 4, 2007 you agreed to provide the disclosures required by SFAS no. 115 as they relate to your nuclear decommissioning trust fund assets. Please revise to include the disclosures required by SFAS no. 115.

     Response: As disclosed in Note 6 — Nuclear Decommissioning Trust Fund and as more fully described in Comment #6 in our letter to the Staff dated May 14, 2007, we account for our activities related to the decommissioning of our STP nuclear facility in accordance with ASC 980 (SFAS No. 71) because these activities are subject to approval by an independent third party regulator, with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since we are in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all movements in the following accounts are offset by entries to the Nuclear Decommissioning Trust Liability to the ratepayers, and no amounts are recorded in our income statement or to our accumulated other comprehensive income:

	•		the Nuclear Decommissioning Trust Fund (e.g., gains/losses on assets, payments received by the trustee from ratepayers, impairment losses);
	•		the Nuclear Decommissioning Reserve representing the asset retirement obligation (“ARO”) (e.g., accretion, payments, updated forecasts);
	•		the ARO asset included within Property, Plant and Equipment (e.g., depreciation, changes in value due to updated forecasts).

     We acknowledge the Staff’s position that compliance with the disclosure requirements of ASC 320 (SFAS 115 and FSP SFAS 115-1/SFAS 124-1) is required regardless of whether a company has the ability to utilize the accounting prescribed in ASC 980. We believe our existing disclosure (i.e., of aggregate fair value by major security type in Note 6 and proceeds from sales of NDT securities in the Consolidated Statements of Cash Flows) substantially meets the requirements of ASC 320 since the disclosures we have omitted generally deal with realized and unrealized gains and losses and other than temporary impairments that do not impact NRG’s financial position or liquidity and therefore we believe are not material to our investors. Consequently, we have omitted disclosures on:

	•		total gains for securities with net gains in accumulated other comprehensive income;
	•		total losses for securities with net losses in accumulated other comprehensive income;
	•		gross realized gains and losses that have been included in earnings as a result of sales of NDT securities;
	•		the basis on which the cost of a security sold or the amount reclassified out of accumulated other comprehensive income into earnings was determined;
	•		the amount of net unrealized holding gain or loss on available for sale securities that has been included in accumulated other comprehensive income;
	•		for all investments in an unrealized loss position for which other-than-temporary impairments have not been recognized, the aggregate fair value of investments by major security type with unrealized losses and the aggregate amount of unrealized losses (that is, the amount by which cost exceeds fair value), segregated by those that have been in a continuous unrealized loss position for less than 12 months and for 12 months or longer.

     However, to further enhance our future disclosures, we will include the following prospectively commencing with our 2009 Form 10-K:

	•		clarification that the securities held in the NDT are classified as available-for-sale;
	•		for investments in debt securities, information about contractual maturities within 1 year, after 1 year through 5 years, after 5 years through 10 years, and after 10 years.

21.

Please explain to us the regulatory requirements with respect to the investment oversight of the NDT assets. In this regard, we assume a trustee is responsible for managing the trust funds; if our assumption is incorrect, please clarify. If correct, explain how you still maintain the intent and ability to retain investments which may be in an unrealized loss

position. Lastly, explain in detail the investments that have been in an unrealized loss position for greater then twelve months. If you have not taken an other than temporary impairment charge, please explain why not. See SAB Topic 5M.

     Response: NRG’s Nuclear Decommissioning Trust Fund assets are subject to NRC & PUCT guidelines. The NRC states in its regulations that the Decommissioning Trust should not be under the “administrative control of the licensee” and that the day-to-day investment decisions should be made by the trustee or investment manager and not by the licensee. NRG has a prudence obligation with respect to the management of the trust funds, in accordance with guidelines established in PUCT rule 25.303. Our Trustee is The Bank of New York Mellon and we have numerous Investment Managers who make the day to day investment decisions for the trust funds. The NRC defers to the PUCT regarding specific investment guidelines. However, for NDT funds of non-regulated utilities, the NRC prohibits investments in securities of the operator of the facility related to the NDT funds or its affiliates. We went before the PUCT in 2008 as part of our rate case and there were no issues.

     For the reasons discussed above in our response to Comment #20, we do not record “other than temporary impairment charges” to earnings because all movements in the Nuclear Decommissioning Trust Fund are offset by entries to the Nuclear Decommissioning Trust Liability to the ratepayers.

Note 12 — Benefit Plans and Other Postretirement Benefits, page 178

22.

Please explain to us how you calculate the market related value of plan assets as that term is defined in SFAS 87. Since there is an alternative to how you can calculate this item, and it has a direct effect on pension expense, we believe you should disclose how you determine this amount in accordance with paragraph 12 of APB 22.

     Response: Per the definition of Market-Related Value of Plan Assets in the Codification’s Master Glossary (paragraph 30 of SFAS 87), the market-related value of plan assets shall be either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. We determine the market-related value of our plan assets at fair value. In accordance with the Staff’s comments, NRG will prospectively disclose in future filings, commencing with our 2009 Form 10-K, that the market-related value of plan assets is the fair value of the assets.

Note 23 — Environmental Matters, page 211

23.

Please explain in detail why you labeled your future estimated environmental capital expenditures of $1.2 billion as unaudited, or revise. In this regard, SAB Topic no. 5-Y requires the disclosure of future costs related to environmental compliance.

     Response — Our understanding is the required disclosure of future costs for site restoration and other environmental remediation costs under SAB Topic 5-Y relate to loss contingencies that fall within the scope of ASC 410-30 (SOP 96-1). The amounts we have disclosed do not relate to remediation of environmental contamination within the scope of ASC 410-30, but rather compliance with federal and state air quality rules as part of our normal operations, and therefore we do not believe that they fall under SAB Topic 5-Y. We make the disclosure in our Management Discussion and Analysis as it impacts our forward-looking liquidity, and chose to repeat the disclosure within the Environmental Matters footnote to increase transparency. It is labeled as “unaudited” because it is a forward-looking estimate which is based on managements’ estimates for current and proposed legislation; however, this is not a current obligation.

Signatures

24.

Form 10-K requires the annual report to be signed by the registrant and on behalf of the registrant by its principal executive officer, principal financial officer and principal accounting officer and a majority of the board of directors in their capacity as such. Refer to Form 10-K and General Instruction D(2)(a). Currently, it appears that your principal financial officer and principal accounting officer have signed the Form 10-K on behalf of the registrant and not in their respective capacities. Therefore, please confirm whether your principal financial officer’s and principal accounting officer’s signatures are intended to comply with both requirements set forth in General Instruction D(2)(a), and please ensure that going forward an authorized officer of the registrant signs on behalf of the registrant and that the principal executive officer, principal financial officer and principal accounting officers sign in their capacity as such, along with a majority of the board of directors.

     Response: We acknowledge the Staff’s comment and will ensure, commencing with our third quarter 2009 Form 10-Q, that it is clear that an officer has signed on behalf of the registrant and that the principal executive officer, principal financial officer, and principal accounting officer sign in their respective capacity.

Exhibits 31.1, 31.2 and 31.3

25.

Please revise the certifications filed as Exhibits 31.1, 31.2 and 31.3 to conform with the language included in Item 601(b)(31) of Regulation S-K. We note that you have changed the word “us” to “the Company” in paragraphs 4(a), (b) and (c).

     Response: We acknowledge the Staff’s comment and will make the change in our certifications filed with the next Forms 10-Q and 10-K.

Amendment No. 1 to Form 10-K for the Fiscal Year Ended December 31, 2008

Item 10 — Directors, Executive Officers and Corporate Governance, page 2

26.

We note several instances where you do not discuss a director or executive officer’s business experience for the past five years, other than his or her position as a director of NRG Energy. Specifically, we note the following:

	•		There is no discussion of Mr. Cosgrove’s business experience from September 2002 to the present,
	•		There is no discussion of Mr. Hantke’s experience from January 2006 to the present,
	•		There is no discussion of Mr. Luterman’s experience from October 2007 to the present,
	•		There is no discussion of Mr. Young’s experience from July 2003 to the present,
	•		You do not provide the time periods that Mr. Gutierrez served in the positions you list for his business experience prior to March 2008,

	•		You do not disclose when Mr. Howell joined NRG, nor the date upon which he ceased serving as the President of Dominion Energy Clearinghouse,
	•		You do not disclose Mr. Howell’s business experience for the required time period preceding March 2008,
	•		You do not disclose the time period that Mr. Murphy served as the partner in charge of the energy practice at Hunton and Williams, and
	•		You do not disclose the time periods for Ms. Wilson’s business experience prior to joining you in September 2008.

In the event that a registrant was retired during the respective time period, please
state so. Refer to Item 401(e) of Regulation S-K.

     Response: We acknowledge the Staff’s comments and will account for all time periods of a director’s or executive officer’s business experience over the past five years, including where such director or executive officer was retired, in future filings beginning with our next proxy statement or Form 10-K.

Item 11 — Executive Compensation, page 12

Annual Incentive Compensation, page 16

NEO Weighed Performance Criteria (%), page 17

27.

We note the table at the top of page 17 that sets forth the weight of each performance criterion applied in determining each NEO’s Annual Incentive Compensation. Please expand your disclosure to briefly discuss why and how you chose the specific weighting you applied to each NEO. In this regard, we note your general description in the second and third paragraphs of page 16, but it does not appear that you describe how these concepts were individually applied in determining performance criterion weighting for each NEO.

     Response: We acknowledge the Staff’s comment and will include disclosure in our future filings beginning with our next proxy statement or Form 10-K substantially in the same manner as provided below, including specific attribution of the criteria to the 2009 NEOs:

AIP Performance Criteria - The following tables provide the 2009 performance criteria established for the NEOs and, for each NEO, the weight each criterion is given with respect to individual NEO performance. The criteria are used in determining the AIP payment as described in more detail below and are designed to achieve the Company’s primary short-term goals and long-term business objectives, such as maintaining financial strength and stability, reducing the volatility of cash flows, increasing value at existing sites, positioning the Company for success under increasing environmental constraints, and optimizing the Company’s capital allocation strategy. The criteria for the Chief Executive Officer are established by the Committee, based upon meetings with Chief Executive Officer and discussions regarding performance goals of the Company and himself. The criteria for the other NEOs are established by the Chief Executive Officer, in consultation with the Committee, and subsequently reviewed and approved by the Committee. The criteria for all NEOs are based upon the Company’s business strategy and individual development year-over-year, in conjunction with applicability of the criteria to the NEO’s business unit. For example, for the positions of Chief Executive Officer and Chief Financial Officer, the

performance criteria are weighted towards overall Company financial performance due to the nature of their respective position with Company; whereas, in addition to overall Company performance, a Regional President’s performance criteria are weighted towards regional financial performance and safety and/or environmental performance due to the Regional President’s oversight of regional financial, safety and environmental performance. Furthermore, certain criteria, such as staff development and retention, apply to all NEOs, and certain other criteria are applied to areas of focus for that particular year, such as actual expenses in comparison to budgeted expenses in a particular business unit.

AIP Targets and Calculation, page 17

28.

We note that you have quantified certain of your 2008 Performance Criteria, which you identify on page 16, such as Consolidated Adjusted Free Cash Flow and Consolidated Adjusted EBITDA. However, it does not appear that you provide quantified information for all of your targets that have objective performance goals associated with them, such as Regional Adjusted EBITDA. In this regard, please revise to provide these targets and generally clarify which of your 2008 Performance Criteria are subject to objective versus subjective goals.

     Response: We acknowledge the Staff’s comment and in light of the fact that the objective performance criteria, any targets, and the identity of the NEOs change each year, we will include the appropriate quantitative disclosure, where applicable, in our future filings beginning with our next proxy statement or Form 10-K.

Form 10 — Q for the Quarterly Period Ended March 31, 2009

General

29.

Please address the above comments regarding your Form 10-K to the extent they are applicable to your Form 10-Q for the quarterly period ended March 31, 2009.

     Response: We acknowledge the Staff’s comment and will address the above comments to the extent they are applicable to our next Form 10-Q filing.

Form 10 — Q for the Quarterly Period Ended June 30, 2009

Note 3 — Business Acquisition, page 15

30.

We note you novated certain in-the-money trades with Merrill Lynch. Please summarize for us how you were previously accounting for these trades. Tell us how the novation agreement with Merrill Lynch affected the accounting for these trades. In this regard, please advise why you are still recording realized and unrealized gains/losses on these novated trades.

     Response: NRG Power Marketing LLC (“PML”) and Reliant Energy Power Supply LLC (“REPS”) are wholly owned entities of NRG. The original parties to the novated transactions were PML and external third parties. The only change to the transactions as a result of the novations was a change of the NRG wholly owned entity in the transaction from PML to REPS. Thus, the novation of these transactions was considered a modification of the transaction for the NRG entity in the transaction and not a net settlement or termination of the transaction. These transactions between NRG (consolidated entity) and the counterparties are still open and will be settled in the future. As a result, there was no accounting impact on NRG’s consolidated financial statements.

     The novated transactions are financial sales of natural gas to the counterparties covering the period from 2009 through 2012 to hedge our Texas baseload generation. Approximately half the fair values of these transactions were accounted for as cash flow hedges. On the date of novation, NRG elected to de-designate these cash flow hedges and treat them as mark-to-market accounting prospectively. As the underlying baseload power generation is still probable, the gains related to the cash flow hedges remain frozen in OCI and will be amortized into income when the underlying power is generated. The other half of the fair values of these transactions were accounted for as mark-to-market transactions before the novations and continue to be treated as mark-to-market transactions after the novations.

     We continue to provide mark-to-market accounting on the open positions and record realized gains or losses on these trades as they settle with the counterparties.

31.

We note you recognized a $31 million non-cash gain on the settlement of a pre-existing relationship with Reliant Energy. Please explain to us how the settlement gain was measured. Further, tell us if there were any stated settlement provisions in the contract that provided a remedy to Reliant Energy in the event of a change in control.

     Response: In September 2007, Reliant Energy and NRG entered into physical power capacity contracts to call on certain NRG gas plants in the ERCOT market to enable Reliant Energy to meet its load obligations. NRG elected the scope exception under ASC 815-10-15-45 (paragraph 10(b)(4) of SFAS 133) and treated these transactions as Normal Purchase and Normal Sale. Thus, these transactions were not recorded on NRG’s balance sheet prior to and as of the date of acquisition. The fair value of these contracts as of the acquisition date was a positive $31 million for NRG.

     Upon the acquisition of Reliant Energy, these transactions were considered to be an effective settlement of a pre-existing contractual relationship subject to ASC 805-10-55-21 (paragraph A79 of SFAS 141(R)). Due to the absence of any stated settlement provisions that provided a remedy to Reliant Energy, including in the event of a change in control, we determined that ASC 805-10-55-21(b)(2) was not applicable, and that pursuant to ASC 805-10-55-21(b)(1), NRG should recognize a gain measured as the amount by which the contracts were favorable from the perspective of the acquirer when compared with pricing for current market transactions for the same or similar items. Since these contracts were not on NRG’s balance sheet, we recorded their fair value of $31 million as a gain.

32.

Please tell us your process for identifying all acquired intangible assets. Further, please advise why trade names are being amortized on a straight-line basis over 15 years.

     Response: Utilizing the guidance in ASC 805-20-25-10 to 15 and ASC 805-20-55-2 to 57 (paragraphs A16 through A56 of FAS 141R), our process to identify all acquired intangible assets considered Identifiable, as defined in ASC 805-20-20 (paragraph 3(k) of FAS 141R), involved a thorough review of all contracts and legal rights to identify intangibles arising from the “contractual-legal criterion”, as well as a search for any other customer-based, technology-based, artistic-related or marketing-related intangibles that met the “separability criterion”. We conducted an initial review of material contracts during due diligence followed by a thorough review after closing. We also conducted interviews with employees of the target company and outside advisors to help us understand the existence and nature of potential intangibles in the Texas electric retail industry.

     In regards to the trade name, the Reliant Energy brand was established approximately ten years ago, and is a leading brand in the Houston market with high customer satisfaction ratings and name recognition. Reliant also has spent considerable marketing dollars, including entering into a long-term stadium naming license expiring in 2032 that enhances visibility of the trade name. Thus, NRG attributed value to the trade name when negotiating the acquisition, and continues to use it post-acquisition. Considering the turnover and name changes in the independent power producer and utility industries and related patterns of name changes in the ERCOT market, we concluded that the Reliant Energy trade name is not indefinite-lived. We considered various factors, such as the current age of the Reliant brand, management’s intent to continue using the name at the current time, and feedback from external consultants regarding their experience with similar trade names, and concluded that the trade name is a long-lived asset for which we believe a reasonable remaining useful life to be 15 years.

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

cc:		Robert Babula, Staff Accountant, Securities and Exchange Commission Michael Bramnick, General Counsel, NRG Energy, Inc. Jim Ingoldsby, Chief Accounting Officer, NRG Energy, Inc.