May 24, 2016

Securities and Exchange Commission

Division of Corporation Finance

100 F Street N.E.

Washington, D.C. 20549

Attn: Jennifer Thompson, Accounting Branch Chief

Re:		NRG Energy, Inc.
		NRG Yield, Inc.
		Forms 10-K for the Fiscal Year Ended December 31, 2015
		Filed February 29, 2016
		Forms 8-K filed February 29, 2016 and May 5, 2016
		File Nos. 1-15891 and 1-36002

Dear Ms. Thompson:

We hereby respond to the comments made by the Staff in your letter dated May 10, 2016 related to the above referenced filings of NRG Energy, Inc. (the “Company”) and NRG Yield, Inc. (“Yield”). 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 filing; (ii) staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and (iii) the Company may not assert staff comments as a defense in any proceeding initiated by the 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 the Company’s responses are as follows:

NRG Energy, Inc. Form 10-K for the Fiscal Year Ended December 31, 2015

Selected Financial Data, page 61

2. We note your breakdown of operating revenues on page 61 and your disclosure that energy revenue “consists of revenues received from third parties.” Your table on page 19, however, indicates that such energy revenues include inter-segment sales between NRG Business and NRG Home. Please revise your page 61 disclosures to address this inconsistency and consider separately quantifying the amount of inter-segment energy revenues included in the table.

In future NRG filings, we will revise the disclosures on page 61 to read as follows: “Energy revenue consists of revenues received from third parties, as well as from the Company’s retail businesses, for sales of electricity….” We will also add a footnote to the table to note the amount of inter-segment sales within the operating revenues table, similar to the

disclosure that we provide in our Segment Reporting footnote as found on pages 190 to 193 of NRG’s 2015 Form 10-K.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Consolidated Results of Operations, page 66

3. We note the prominent presentation and discussion of economic gross margin, a non-GAAP measure, in your results of operations narrative. Please revise your discussion and analysis to provide presentation with equal or greater prominence of financial measures presented in accordance with GAAP. In doing so, separately quantify and discuss changes in your revenues and cost of sales and disclose the nature of costs included in cost of sales. Refer to Item 10(e)(1)(i)(A) of Regulation S-K. Also discuss the extent to which material changes in revenues are attributable to changes in prices or volumes.

In future filings, we will revise our economic gross margin table (as detailed on page 68 of the NRG 10-K) to reconcile to GAAP gross margin, which now reflects our current segment names, as follows:

	Generation/Business																											Elim-
(In millions except otherwise noted)	Gulf Coast			East			West			B2B			Elim- inations			Subtotal			Retail Mass			Renew -ables			NRG Yield			inations/ Corporate			Total
Energy revenue	$	2,548		$	2,926		$	269		$	—		$	—		$	5,743		$	—		$	444		$	405		$	(1,098	)	$	5,494
Capacity revenue	291			1,345			195			6			—			1,837			—			—			341			(14		)	2,164
Retail revenue	—			—			—			1,499			—			1,499			5,389			—			—			25			6,913
Other revenue	70			68			11			208			(59		)	298			—			34			179			(124		)	387
Operating revenue	2,909			4,339			475			1,713			(59		)	9,377			5,389			478			925			(1,211		)	14,958
Cost of fuel	(1,214		)	(1,446		)	(159		)	—			—			(2,819		)	(8		)	(4		)	(43		)	62			(2,812
Other costs of sales	(237		)	(493		)	(33		)	(1,468		)	—			(2,231		)	(3,883		)	(3		)	(28		)	1,119			(5,026
Economic gross margin	$	1,458		$	2,400		$	283		$	245		$	(59	)	$	4,327		$	1,498		$	471		$	854		$	(30	)	$	7,120
Mark-to-market for economic hedging activities
Contract amortization and emissions credit amortization
Gross margin	$

We acknowledge the Staff’s request for us to separately quantify and discuss changes in our revenue and cost of sales and disclose the nature of costs included in costs of sales. We respectfully submit the following:

· In order to calculate economic gross margin, we exclude from gross margin the following items: a) mark-to-market for economic hedging activities, b) contract amortization revenues and c) contract amortization and emissions credit amortization expenses. Mark-to-market for economic hedging activities reflect the fair value of open hedges and we describe the activity and related drivers in detail for each of the periods presented, in the section immediately following economic gross margin on page 72 of NRG’s 2015 Form 10-K and with equal prominence. We do not describe the variance in contract amortization for NRG because the variances are not material, as the related assets are amortized on a straight-line basis over the contractual term and related variances are typically due to acquisitions. This information is also detailed in Note 11, Goodwill and Other Intangibles. Amortization of emissions credits relates to credits acquired in business acquisitions and is immaterial. We have

historically explained such variances for NRG Yield and we will continue to provide disclosure for all material variances that impact gross margin.

Based on this information, we believe we have provided the same disclosure that we would include to describe the variances in gross margin as calculated in accordance with GAAP.

· We have historically explained all significant revenue and cost drivers, including the impact of price and volumes changes, as applicable. We also provide all of the revenue line items and cost of sales for each segment in the tables so that a reader can analyze and recalculate the quantitative changes that are reflected in our analysis of gross margin and we provide business metrics in the economic gross margin table, such as megawatt hours (MWh) and weather metrics, which allow a reader to calculate variances that could be useful to their analysis.

· To the extent the drivers of revenue and cost variances are inter-related, we explain the impact to gross margin instead, as it avoids repetition and focuses on the true drivers of the variances while reflecting how we manage the business. We do not believe that splitting this analysis out between revenue and costs would be meaningful to the reader and furthermore, we believe this would cause additional confusion. Drivers that impact both revenue and costs in a corresponding manner are described and include: acquisitions, plant deactivations, outages, plant conversions and coal-to-gas switching due to low natural gas prices. We strive to quantify these changes highlighting variances driven by changes in generation (volume) and driven by price (including hedged prices).

· Additionally, we present cost of fuel separately for each segment and each period presented, which represents the majority of cost of sales for the Generation/Business segment. The remaining costs primarily represent purchased energy, capacity and emission credits, which we will highlight in future filings through a footnote to the table. Cost of sales for the retail businesses (B2B and Retail) reflect cost of energy and a detailed description of these costs is provided in Note 2, Summary of Significant Accounting Policies.

Mark-to-market for Economic Hedging Activities, page 72

4. Based on a previous response letter dated August 20, 2014, it is our understanding that the line item “Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges” in your page 72 table is intended to provide quantified information regarding unsettled positions that are subject to future price fluctuations. Please revise this line item description to provide investors with a clear explanation of what the amounts in this line item represent.

The table on page 72 of NRG’s 2015 10-K summarizing our mark-to-market for economic hedging activities presents the impact of changes in the fair value of derivative instruments used for economic hedging activities on the statement of operations. The line item “Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges” represents the roll-off of the fair value of derivative transactions that were unrealized in the prior period but are now realized and settled and are no longer subject to future price movements. These unrealized gains or losses are reversed and a corresponding (though not always equal) amount is recorded within the respective revenue or cost line items such as “Energy revenues” or “Cost of sales” (see line items on page 66) based on settled prices. As hedges settle, the settled gains or losses are reflected in the same revenue or cost of operations caption in the Company’s consolidated statement of operations as the unrealized gains or losses. In future filings, NRG will add the following language to the existing language below the “Mark-to-market for Economic Hedging Activities” table as follows (additional language in bold):

“Mark-to-market results consist of unrealized gains and losses. The corresponding results for settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.”

Indemnity Receivable, page 91

5. We note that you have a $75 million indemnity receivable from SunPower that SunPower “has refused to honor” and that is currently subject to litigation. Please tell us whether or not you have recorded this receivable within your financial statements and, if so, clarify when and how you recognized the receivable and the reasons supporting your accounting treatment.

As we have previously submitted to the Staff in our response to question 8 of your comment letter with respect to the 2013 NRG Form 10-K on July 17, 2014, our historical policy with respect to Section 1603 cash grants is to record a receivable once there is reasonable assurance of receipt, which was typically at the time of application acceptance. Accordingly, NRG recorded a receivable for the CVSR project at the time of application acceptance, which was reduced by a reserve for sequestration and by cash payments received. The receivable was recorded with a corresponding reduction to the book basis of the property, plant and equipment.

Additionally, as previously submitted to the Staff in the same response, we subsequently reserved $32 million and reduced the receivable to $75 million, which reflects the amount that is subject to the litigation with SunPower. This reduction to the receivable was recorded with a corresponding increase to the book basis of the property, plant and equipment.

While the $75 million receivable no longer pertains to Section 1603 cash grants, SunPower was the construction contractor for the CVSR project and accordingly, cash payments to and from SunPower are reflected within the cost to construct the project. The Company believes that the $75 million receivable is appropriately recorded as a reduction to the cost of the construction project and maintains its position that the receivable continues to be collectible, based on our counsels’ view of the expected outcome of the litigation with SunPower. Though we have a high level of confidence that the amount is collectible, if NRG does not collect the full amount of the receivable, the difference will be reflected as an increase to the book basis of the property, plant and equipment, as it will reflect a change in the cost paid to SunPower to construct the CVSR facility.

Capital Expenditures, page 94

6. We note that you present your capital expenditures table “net of financings.” Please tell us what you mean by this statement and consider revising your disclosures for clarity.

In future filings, beginning with our 2016 Form 10-K, we will remove the words “net of financings” from the line entitled “Total cash capital expenditures for the year ended December 31, 201X” as this line is the gross figure for cash capital expenditures. The line items entitled “Funding from debt financing and NRG Yield, Inc. equity issuance, net of fees” and “Funding from third party equity partners and cash grants” are intended to reduce the amount of cash capital expenditures incurred by NRG to reflect the net cash that NRG has spent after receiving the proceeds from various financing arrangements, including the issuance of debt and equity as well as contributions from noncontrolling partners and 1603 cash grants. In future filings, we will indent these line items to show that they are being

subtracted from the gross figures to present a net amount of cash paid for capital expenditures and investments.

Cash Flow Discussion, page 99

7. Please provide a more informative analysis and discussion of financial condition and changes in cash flows from operating activities, including changes in working capital components, for each period presented. In doing so, explain the underlying reasons and implications of material changes between periods to provide investors with an understanding of trends and variability in cash flows. Refer to Item 303(a) of Regulation S-K and SEC Release No. 33-8350.

We note that typically the variance in working capital is comprised of many line items that are not individually material. In future filings, we will ensure that we describe any material changes in working capital components in order to comply with the SEC’s guidance on cash flow discussion.

For NRG, the changes in working capital typically include: 1) timing of rent payments for facility operating leases; 2) timing of inventory purchases in preparation for winter months; 3) timing of accounts payable for major outages; 4) timing of payroll obligations and 5) timing of accounts receivable collections depending on volumes and weather in December.

For NRG Yield, Inc., the changes in working capital typically reflect timing of accounts payable for major outages and timing of accounts receivable collections depending on volumes and weather in December.

Financial Statements for the Fiscal Year Ended December 31, 2015

Note 10 — Asset Impairments, page 161

8. We note that you entered into an agreement to sell your 100% interest in Seward during November 2015 and recorded a $134 million impairment charge since the sales price was less than the carrying amount of the assets. Please tell us in sufficient detail why an impairment charge was not necessary in a period prior to your sales agreement. Specifically tell us if you performed a held and used impairment test on your Seward assets prior to the fourth quarter of 2015. If the Seward impairment was limited to adverse circumstances or events that transpired during the fourth quarter of 2015, please advise.

ASC 360-10-35-21 states that a long-lived asset shall be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. There were no events or changes in circumstance leading up to the sale of Seward that indicated an impairment may have existed. Discussions regarding the potential sale of the Seward plant assets were in preliminary phases, noting that the terms of sale, including the transaction price, were not yet determinable or estimable, nor did the preliminary plans indicate that the carrying amount of the asset exceeded its fair value. Furthermore, the facility had not historically experienced continuing losses, noting strong operating results in 2014 and positive forecast data for 2015. Had the sale process not continued in a positive manner, we would have continued to operate the facility. Accordingly, an impairment test was not performed prior to the fourth quarter of 2015. We do, however, perform a review of the cash flows for all facilities on an annual basis during our impairment testing. We note that the undiscounted cash flows for Seward were greater than the carrying value of the assets, supporting our view that no impairment test was necessary.

The Seward impairment was related to events that transpired during the fourth quarter of 2015. The sale was approved by the Board of Directors during the fourth quarter at which time the Company concluded that the asset was held for sale. As the sale price was less than the current carrying amount of Seward, the Company recorded an impairment to reflect the held for sale assets at fair value.

9. We note that you recorded impairment charges of approximately $1.5 billion and $1.3 billion during the fourth quarter of 2015 related to two coal-fired facilities located in Texas. It appears such charges were related to updating estimates related to “long-term prices in connection with the preparation” of your annual budget. Please specify the nature of the “long-term prices” used in your impairment assessment and clarify if you regularly update and assess such estimates on a quarterly basis. If so, tell us the circumstances that changed from prior periods that culminated in an impairment being necessary in the fourth quarter of 2015 and not in an earlier period.

On an annual basis in connection with the overall budgeting process, the Company evaluates each of its plants for expected profitability and makes decisions with respect to how and when each plant will operate. The Company finalizes its five-year budget and terminal year budget (or “Budget”), including approval from the Board of Directors, in the fourth quarter of each year. The 2016 Budget was approved by the Company’s Board of Directors on December 2, 2015.

As part of the process undertaken to establish the five-year and terminal year budgets, the Company develops its long-term view on prices including the price of natural gas, heat rates, other indices and impact of anticipated environmental regulations. The Company estimates gross margin for the five years in the budget period using market power prices driven by natural gas prices and heat rates. For the terminal view (or “terminal year”), the Company develops a fundamental view on power prices, which reflects the implied power price and heat rate that would support new build of a combined cycle gas plant in the Texas region. During 2015, the Company noted a continued decline in natural gas prices, with Henry Hub average natural gas prices decreasing from $4.41/MMBtu for the year ended December 31, 2014 to $2.66/MMBtu for the year ended December 31, 2015. In connection with this continued decline, the Company lowered its long-term view of natural gas prices from $5.00/MMBtu utilized in the terminal year for the 2015 Budget to $4.00/MMBtu in the terminal year for the 2016 Budget. This resulted in a significant decrease in expected power prices for the terminal year.

Additionally, in October 2015, the EPA finalized the Clean Power Plan, or CPP, and entered it into the Federal Register. The CPP is expected to face numerous legal challenges that will take several years to resolve and was stayed by the U.S. Supreme Court on February 9, 2016. In connection with these changes in anticipated environmental regulations, the Company also revised its view on the expected impact of the CPP on terminal year power prices.

The decrease in terminal year power prices had a significant negative impact on the terminal year cash flows for each of the plants located in Texas. The Company viewed this as an indicator of impairment with respect to each of the long-lived assets within Texas and performed the impairment test under ASC 360, Property, Plant and Equipment. While we review current market data, including power, gas and other price indices, and revise our view of gross margin at a minimum on a quarterly basis, we do not revise our fundamental view of long-term natural gas, power prices and other indices other than during the annual budget process, due to the significant amount of effort that the development of our long-term view requires, including taking into account any new legislation around environmental laws and

other regulations impacting the power industry, and updating our estimates to reflect the related changes in operations and maintenance expense and capital expenditures. The most significant impact to our expected future cash flows is driven by our fundamental view and its impact on the terminal year cash flows.

Note 11 — Goodwill and Other Intangibles, page 163

10. We note that you recorded a $1.4 billion goodwill impairment loss related to your NRG Texas reporting unit during the fourth quarter of 2015 and that step one of the impairment test resulted in a reporting unit carrying value that was 76% in excess of fair value. Considering this significant carrying value excess, please tell us in sufficient detail why an impairment and/or interim impairment test was not necessary prior to the fourth quarter. Although it appears you revise certain estimates, such as forecasted power and fuel prices, during each fourth quarter, clarify if you regularly update and assess such estimates in the first three quarters of your fiscal year. If so, tell us the circumstances that changed from prior periods that culminated in an impairment being necessary in the fourth quarter of 2015 and not in an earlier period. Due to the significant 76% shortfall, it appears to us that the impairment might have existed prior to your annual impairment testing date. We did not see any cautionary disclosure within your third quarter 2015 Form 10-Q regarding the potential for an imminent material goodwill impairment charge.

As noted in the previous response, the Company analyzes its view on long-term prices in conjunction with the annual budgeting process which is finalized in the fourth quarter with Board of Director approval of the Budget. The key driver of the 76% shortfall is the decrease in terminal year cash flows of approximately $225 million across the Texas fleet, which is driven by the decrease in view on terminal year power prices. This change is generally the result of the Company’s revised long-term view of natural gas prices, the resulting impact on power prices and other indices. Because the terminal year cash flows are utilized for each year in the remaining useful life of the asset, grown at a reasonable inflation rate, the decrease in terminal year cash flows was the significant driver in the Texas goodwill and fixed asset impairments.

Additionally, during the process of completing the impairment test, as a result of the significant decrease in estimated terminal year cash flows as well as the expected impact from the new legislation (CPP), the Company further determined that it would no longer be appropriate to assume the plants within Texas would continue to operate in perpetuity, as it would no longer be economical to incur significant capital expenditures beyond the useful lives of the plants in order to extend their utility nor would it be likely that new plants would be constructed in the region to replace the Company’s generation in Texas. As such, cash flows for the generating assets included in the Texas reporting unit were assumed through their respective estimated remaining useful lives.

With regards to cautionary disclosure within NRG’s third quarter 2015 Form 10-Q, the Company included in Part 1, Item 2, Critical Accounting Policies and Estimates, on page 98 the following disclosure regarding the potential for a material goodwill impairment charge:

“The Company performs its annual test of goodwill impairment during the fourth quarter. The Company tests its long-lived assets for impairment whenever indicators of impairment exist. The Company notes that if natural gas prices continue to decrease, this could have a negative impact on the fair value of the reporting units that have goodwill balances. Additionally, continued decreases in natural gas prices could result in an adverse change in the manner that long-lived assets are used, or result in the Company selling an asset before

the end of its previously estimated useful life, at a price that is lower than its carrying amount. Accordingly, if these decreases continue, it is possible that the Company’s goodwill or long-lived assets will be impaired.”

Note 12 — Debt and Capital Leases, page 166

11. We note that GenOn has a long-term debt balance approximating $2.8 billion at the end of fiscal year 2015 and that such debt is non-recourse to you. We further note on page 171 that GenOn debt is secured by the assets in the respective GenOn subsidiaries and that the GenOn Senior Notes are the sole obligation of GenOn and are not guaranteed by any subsidiary or affiliate of GenOn. Based on your disclosures on page 88, we note that GenOn “may be unable to generate sufficient cash flow from operations to meets its long-term liquidity requirements, including operating, maintenance and capital expenditures and debt service payments” due to the sustained decline in natural gas prices and its resulting effect on wholesale power prices. We also note from page 88 that Standard & Poor’s lowered its corporate credit ratings for certain GenOn entities. Please tell us and disclose the ramifications on your liquidity, results of operations, and financial condition of GenOn failing to generate sufficient cash flows to fund its debt requirements.

With respect to the GenOn Senior Notes that mature in 2017, we are currently considering a number of options, as disclosed in NRG’s 2015 Form 10-K and first quarter 2016 10-Q. These options may include, but are not limited to, paying the 2017 and 2018 bonds from proceeds from the sale of certain generating assets, including the recently completed sales of Seward and Shelby and the recently announced sale of Aurora, as well as refinancing the remaining debt. We recently announced that we intend to reach out to the GenOn lenders to discuss potential options for restructuring these obligations.

We believe that should GenOn fail to generate sufficient cash flows to fund its debt requirements, the impact to our liquidity and financial condition would not be material. We have disclosed the following with respect to liquidity and financial condition in our 2015 Form 10-K:

· On page 87, we present the cash and cash equivalents for GenOn and subsidiaries and below that, on the same page, we disclose the distribution restrictions on GenOn’s cash and cash equivalents and the restrictions of certain of its subsidiaries.

· Letters of credit issued on behalf of GenOn subsidiaries and within the availability of the intercompany credit facility between NRG and GenOn have reduced the credit facility availability included within our liquidity position.

· Intercompany balances are related to current operating activity are settled primarily on a monthly basis. The company expects that any exposure from these amounts will be immaterial to the overall financial statements, due to timely settlement of such balances.

With respect to results of operations, GenOn’s results are consolidated into NRG’s so the expected impact will be driven by commodity and power prices, which we cannot predict and have disclosed to the extent we have available information, or have provided disclosure in the risk factors related to factors we cannot predict. We do not anticipate any other impact to the

Company’s results of operations, other than an impact of restructuring the debt, which we cannot predict at this time.

Note 29 — Condensed Consolidating Financial Information, page 210

12. It appears that the NRG Energy, Inc. column of your condensed consolidating financial information column represents your Schedule I presentation of condensed financial information of the registrant. Please provide all disclosures required by Rule 12-04(a) and (b) of Regulation S-X or tell us how you complied with such requirements.

Rules 12-04(a) and (b) require that we provide financial information as to financial position, cash flows and results of operations of the registrant as well as disclosures regarding material contingencies, long-term obligations and guarantees, which need not be repeated if they are separately disclosed in the consolidated footnotes. We have not repeated such disclosures as this information is detailed separately in the consolidated footnotes. We have provided a cross-reference on page 214, which states “For a discussion of NRG Energy, Inc.’s long-term debt, see Note 12, Debt and Capital Leases to the consolidated financial statements. For a discussion of NRG Energy, Inc.’s contingencies, see Note 22, Commitments and Contingencies to the consolidated financial statements. For a discussion of NRG Energy, Inc.’s guarantees, see Note 26, Guarantees to the consolidated financial statements.”

Because there are no amortizing payments, apart from an immaterial amount for the term loan facility, and the maturity dates and related terms of each of NRG Energy, Inc.’s long-term obligations is described in Note 12, Debt and Capital Leases, no five-year maturity schedule was deemed necessary. Dividends and intercompany payments to NRG Energy, Inc. are reflected within the consolidating statements of cash flows.

Schedule II Valuation and Qualifying Accounts, page 223

13. We note that $271 million of the fiscal 2015 increase to your income tax valuation allowance is included within the “Charged to Other Accounts” column. Please tell us what this amount represents and why it was not charged to costs and expenses.

This amount represents the valuation allowance recorded on acquired state deferred tax assets that require a full valuation allowance as well as the valuation allowance offsetting the deferred tax asset recorded in accumulated other comprehensive income (AOCI) pursuant to ASC 740-20-45-11b.

Forms 8-K filed February 29, 2016 and May 5, 2016

14. Consistent with the guidance in Item 10(e)(1)(i)(A) of Regulation S-K, please revise future earnings releases to ensure that you do not give greater prominence to non-GAAP measures than you do to the most directly comparable GAAP measures. We refer you to your references to Adjusted EBITDA, Free Cash Flow, and Adjusted cash flow from operations throughout the filing including within the introductory bullet points.

We will ensure that future earnings releases do not give greater prominence to non-GAAP measures than the most directly comparable GAAP measures. In future earnings releases, we

intend to present the comparable GAAP measures for each of Adjusted EBITDA (net income) and Free Cash Flow before Growth (cash from operations) within the first section of the earnings release (Results and Financial Highlights).

NRG Yield, Inc. Form 10-K for the Fiscal Year Ended December 31, 2015

Financial Statements for the Fiscal Year Ended December 31, 2015

Note 1 — Nature of Business, page 76

15. You disclose on page 78 that the equity associated with the Class B and Class D common stock held by NRG Energy, Inc., is classified as noncontrolling interest. Please clarify if this statement pertains to the Class B and D units of NRG Yield, LLC held by your parent. If not and the activity associated with your Class B and Class D common shares are classified within noncontrolling interest, please advise us how you determined such classification was appropriate.

We confirm that the NRG Energy’s Inc.’s noncontrolling interest represents its ownership of the Class B and D units of NRG Yield, LLC, as detailed in the table on page 76 of NRG Yield, Inc.’s 2015 10-K.

Note 2 — Summary of Significant Accounting Policies

Revenue Recognition, page 81

16. We note your disclosure on page 12 that you sell electricity and environmental attributes, including renewable energy certificates (“REC’s”), primarily to utilities under long-term, fixed-price PPA’s. Please address the following comments:

· Your disclosure on page 81 indicates that all of your PPA’s are operating leases. Considering your PPA’s are at fixed prices, tell us how such arrangements qualify as leases under ASC 840-10-15-6(c).

Our PPAs generally include a contract price in dollars per MWh subject to certain adjustments. Accordingly, in terms of the strict interpretation of the phrase “contractually fixed per output”, the PPAs are not fixed price per unit contracts.

Below are some examples of such adjustment clauses in the PPAs:

· Time of day pricing adjustments;

· Seasonality pricing adjustments;

· Buyer curtailment clauses stipulating that buyers/off-takers are required to pay the sellers/generators for any deemed energy production lost at certain price-formulae stated in the contract; and

· Performance guarantees which would require a minimum amount of power to be delivered.

We referred to certain industry accounting guides including PwC’s industry Guide “Guide to Accounting for Utilities and Power Companies”, which notes that there are different acceptable interpretations of the phrase “fixed”. Fixed may be interpreted as meaning that the amount is exactly the same throughout the contract (“fixed equals fixed” i.e., fixed

without any variation) or it may mean predetermined at contract inception (“fixed equals predetermined”).

Our policy is to apply the “fixed equal fixed” interpretation and consider any change in price over time to indicate that the price is not fixed at lease inception. As a result, our PPAs are neither contractually fixed per unit of output nor equal to current market price per unit of output at the time of the delivery. As a result, the Company has concluded that the power purchase agreements are considered leases for accounting purposes.

· Tell us how you account for REC’s. Quantify for us and, if material, disclose under ASC 280-10-50-40 the amount of REC revenue recognized during the periods presented and the amount of any REC assets recorded on your balance sheet. Alternatively, please clarify if you believe REC’s represent facility outputs and recognize REC revenue as part of the lease of your facilities and do not separately allocate such revenue.

We believe that the renewable energy certificates (RECs) are government incentives and are not output from the power plant. The majority of the Company’s renewable power plants have bundled PPAs where RECs are sold with energy and/or other attributes. The contract price is negotiated for the underlying MWh generated and bundled price is stated in the PPAs.

We note that the REC markets have significant design differences in different states. Below is a short description of the REC markets in states we operate:

· As stated on page 12 of the NRG Yield 10-K, the majority of the NRG Yield revenue is from PPAs with Southern California Edison (SCE) and Pacific Electric and Gas (PG&E) in California. RECs sold under bundled PPAs are classified as Tier I RECs in California and they do not have a market nor can they be commoditized and hence, a market price for such RECs is not easily determinable.

· We also have several bundled PPAs in other states including Texas. RECs have an observable market in Texas and certain other non-PJM states. However, the price for the RECs has historically been immaterial (ranging from $0.30 to $2.00 per REC). Hence, it is immaterial to the total contract price per unit of output produced.

For the majority of the NRG Yield PPAs, the bundled price cannot be split between RECs and other contract elements. For certain PPAs, while the price of RECs is observable, it is immaterial to the total contract price. Accordingly, there was an immaterial amount of REC revenue recognized in 2015 (approximately 1% of revenue). Because NRG Yield sells all of its RECs at the time electricity is generated, there is no asset related to such RECs on the balance sheet.

NRG accounts for RECs in the same manner. While NRG has several contracts through which it buys and sells RECs in various markets that have a market for RECs, primarily to meet its obligations under retail contracts, these amounts are immaterial and therefore do not require separate disclosures under ASC 280-10-50-40. REC revenue recognized by NRG in 2015 was less than 1% of total revenue. Additionally, the balance of RECs on NRG’s balance sheet as of December 31, 2015 was $7 million.

Note 5 — Investments Accounted for by the Equity Method and Variable Interest Entities, page 90

17. Please provide us with your income significance test supporting your determination that the financial statements of Desert Sunlight are not required to be filed pursuant to Rule 3-09 of Regulation S-X.

The significance tests that we performed are detailed below.

NRG Yield, Inc. significance test as of December 31, 2015:

	(in millions)
Desert Sunlight post- acquisition earnings	$	42
NRG Yield share (25%)	$	10
Basis difference amortization	(3		)
NRG Yield portion of Desert Sunlight income	7
NRG Yield, Inc. portion of Desert Sunlight income (x 53.3% economic ownership of NRG Yield, LLC) (A)	4

NRG Yield pre-tax income	$	67
NRG Yield noncontrolling interest	(42		)
NRG Yield income before noncontrolling interest (B)	25

(A)/(B)	15		%

NRG Energy, Inc. significance test as of December 31, 2015:

	(in millions)
Desert Sunlight post- acquisition earnings	$	42
NRG Yield share (25%)	$	10
Basis difference amortization	(3		)
NRG Yield portion of Desert Sunlight income	7
NRG portion of Desert Sunlight income (x 47.7% economic ownership of NRG Yield, LLC) (A)	3

NRG pre-tax income after noncontrolling interest (average calculation for 5 years) (B)	$	1,054

(A)/(B)	0.2		%

18. It appears that the summarized information presented in Note 5 for your significant equity method investees does not fully comply with Rule 4-08(g). Please note that Rule 4-08(g) requires the summarized information as to assets, liabilities and results of operations as detailed in Rule 1-02(bb) of Regulation S-X. We note that Rule 1-02(bb) requires separate presentation of the amount of noncontrolling interests, if applicable, as well as gross profit (or, alternatively, costs and expenses applicable to revenues) and net income attributable to the entity. Please revise future disclosures if appropriate.

		Sincerely,

		/s/ Kirkland B. Andrews

		Kirkland B. Andrews
		Executive Vice President and
		Chief Financial Officer