EXHIBIT 99.4

The information provided in this Exhibit is presented only in connection with the reporting changes described in the accompanying Form 8-K. This information does not reflect events occurring after February 28, 2012, the date we filed our 2011 Form 10-K, and does not modify or update the disclosures therein in any way, other than as required to reflect the change in reportable segments and the adoption of a new accounting standard, as described in the Form 8-K and set forth in Exhibits 99.1 through 99.5 attached thereto. You should therefore read this information in conjunction with the 2011 Form 10-K and any subsequent amendments on Form 10-K/A and with our reports filed with the Securities and Exchange Commission after February 28, 2012.

Part II

Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations

The discussion and analysis below has been organized as follows:

• Executive Summary, including business strategy, the business environment in which NRG operates, how regulation, weather, competition and other factors affect the business, and significant events that are important to understanding the results of operations and financial condition for the 2011 period;

• Results of operations, including an explanation of significant differences between the periods in the specific line items of NRG's Consolidated Statements of Operations;

• Financial condition addressing credit ratings, liquidity position, sources and uses of cash, capital resources and requirements, commitments, and off-balance sheet arrangements; and

• Critical accounting policies which are most important to both the portrayal of the Company's financial condition and results of operations, and which require management's most difficult, subjective or complex judgment.

As you read this discussion and analysis, refer to NRG's Consolidated Statements of Operations to this Form 8-K, which presents the results of the Company's operations for the years ended December 31, 2011, 2010, and 2009, and also refer to Exhibit 99.1 to this Form 8-K for more detailed discussion about the Company's business.

1

Executive Summary

Business Strategy

NRG Energy, Inc., or NRG or the Company, is an integrated wholesale power generation and retail electricity company that aspires to be a leader in the way the industry and consumers think about, use, produce and deliver energy and energy services in major competitive power markets in the United States. First, NRG is a wholesale power generator engaged in the ownership and operation of power generation facilities; the trading of energy, capacity and related products; and the transacting in and trading of fuel and transportation services. Second, NRG is a retail electricity company engaged in the supply of electricity, energy services, and cleaner energy products to retail electricity customers in deregulated markets through the Retail Businesses. Finally, NRG is focused on the deployment and commercialization of potential disruptive technologies, like electric vehicles, Distributed Solar and smart meter technology, which have the potential to change the nature of the power supply industry.

The Company's core business is focused on: (i) excellence in safety and operating performance of its existing assets; (ii) serving the energy needs of end-use residential, commercial and industrial customers in the Company's core markets with a retail energy product that is differentiated either by premium service (Reliant), sustainability (Green Mountain Energy) or loyalty/affinity programs (Energy Plus); (iii) optimal hedging of baseload generation and retail load operations, while retaining optionality on the Company's peaking facilities; (iv) repowering of power generation assets at premium sites; (v) investment in, and deployment of, alternative energy technologies both in its wholesale and, particularly, in and around its retail businesses and their customers; (vi) pursuing selective acquisitions, joint ventures, divestitures and investments; and (vii) engaging in a proactive capital allocation plan focused on achieving the regular return of and on stockholder capital within the dictates of prudent balance sheet management.

The Company believes that the American energy industry is going to be increasingly impacted by the long-term societal trend towards sustainability which is both generational and irreversible. Moreover, the information technology-driven revolution which has enabled greater and easier personal choice in other sectors on the consumer economy will do the same in the American energy sector over the years to come. As a result, energy consumers will have increasing personal control over whom they buy their energy from, how that energy is generated and used and what environmental impact these individual choices will have. The Company's initiatives in this area of future growth are focused on: (i) renewables, with a concentration in solar development; (ii) electric vehicle ecosystems; (iii) customer-facing energy products and services including smart grid services, nationwide retail green electricity, unique retail sales channels involving loyalty and affinity programs and custom design; and (iv) construction of other forms of on-site clean power generation. The Company's advances in each of these areas are driven by select acquisitions, joint ventures, and investments that are more fully described in Item 1, Business — New and On-going Company Initiatives and Development Projects.

Business Environment

The industry dynamics and external influences affecting the Company and the power generation industry in 2011 and for the future medium term include:

Consolidation — There were several mergers and acquisitions in the U.S. power sector in 2011. Over the long term, industry consolidation is expected to continue.

Environmental Regulatory Landscape — In 2011, a number of U.S. EPA air regulations were finalized providing more clarity on the impact to electric generating units. A number of regulations with the potential for impact are still in development or under review by the U.S. EPA: NSPS for GHGs, NAAQS revisions, coal combustion byproducts, and once-through cooling. While most of these regulations have been considered for some time, the outcomes and any resulting impact on NRG cannot be fully predicted until the rules are finalized. The timing and stringency of these regulations will contribute to a framework for the retrofit of existing fossil plants and deployment of new, cleaner technologies in the next decade. See Item 1, Business — Environmental Matters, for further discussion.

Public Policy Support and Government Financial Incentives for Clean Infrastructure Development — Policy mechanisms including production and investment tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits, RPS, and carbon trading plans have been implemented at the state and federal levels to support the development of renewable generation, demand-side and smart grid, and other clean infrastructure technologies. The availability and continuation of public policy support mechanisms will drive a significant part of the economics of the Company's development program and expansion into clean energy investments.

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Natural Gas Market — The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates power plants. Natural gas prices are driven by variables including demand from the industrial, residential, and electric sectors, productivity across natural gas supply basins, costs of natural gas production, changes in pipeline infrastructure, and the financial and hedging profile of natural gas consumers and producers. In 2011, average natural gas prices were 8% lower than 2010 and comparable to prices seen in 2009. Supply continues to reflect increased production from low extraction cost resources such as the shale basins. In 2012, a mild winter and increased production have led to spot prices dipping into the $2.50/MMBtu range. At these current depressed levels, significant coal-to-gas switching is expected, making wholesale changes to Merit Order in many electric markets. While some gas producers have publicly spoken of scaling back production, it is too early to assess whether there is action behind their words. At current rates of production, storage levels may challenge storage limits later in the year. While the near-term gas price outlook is depressed, a return to normal weather, coal-fired plant retirements due to proposed environmental regulations and Liquid Natural Gas export possibilities may drive higher gas prices in the medium term. 

If long-term gas prices remain depressed, the Company is likely to encounter further reductions in realized energy prices, leading to lower energy revenues as higher priced hedge contracts mature and are replaced by contracts with lower gas and power prices.  The Retail Businesses' gross margins have historically improved as natural gas prices decline and are likely to partially offset the impact of declining gas prices on conventional wholesale power generation.  To further mitigate this impact, NRG may increase its percentage of baseload capacity sold forward using a variety of hedging instruments, as described under the heading Energy Related Commodities in Item 15 — Note 6, Accounting for Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements.  The Company's increased investment in renewable power generation supported by PPAs also mitigates declines in long term gas prices.

Electricity Price — The price of electricity is a key determinant of the profitability of the Company's generation portfolio. Many variables such as the price of different fuels, weather, load growth and unit availability all coalesce to impact the final price for electricity. In 2011, electricity prices in Texas were higher than 2010 due primarily to the extreme weather and record-setting load experienced in August 2011. In NRG's other regions, prices were lower than in 2010, mainly due to lower gas prices and negligible demand growth. The following table summarizes average on-peak power prices for each of the major markets in which NRG operates for the years ended December 31, 2011, 2010, and 2009:

	Average on Peak Power Price ($/MWh)
Region	2011		2010		2009
Texas	$	57.42	$	40.40	$	35.43
Northeast	53.09		56.69		46.14
South Central	36.30		40.25		33.58
West	36.39		40.05		39.70

Weather

Weather conditions in the regions of the United States in which NRG does business influence the Company's financial results. Weather conditions can affect the supply and demand for electricity and fuels. Changes in energy supply and demand may impact the price of these energy commodities in both the spot and forward markets, which may affect the Company's results in any given period. Typically, demand for and the price of electricity is higher in the summer and the winter seasons, when temperatures are more extreme. The demand for and price of natural gas are higher in the winter. However, all regions of the United States typically do not experience extreme weather conditions at the same time, thus NRG is typically not exposed to the effects of extreme weather in all parts of its business at once.

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Other Factors

A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative products for NRG's business. These factors include:

• seasonal, daily and hourly changes in demand;

• extreme peak demands;

• available supply resources;

• transportation and transmission availability and reliability within and between regions;

• location of NRG's generating facilities relative to the location of its load-serving opportunities;

• procedures used to maintain the integrity of the physical electricity system during extreme conditions; and

• changes in the nature and extent of federal and state regulations.

These factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country as a result of regional differences in:

• weather conditions;

• market liquidity;

• capability and reliability of the physical electricity and gas systems;

• local transportation systems; and

• the nature and extent of electricity deregulation.

Environmental Matters, Regulatory Matters and Legal Proceedings

NRG discusses details of its other environmental matters in Item 15 — Note 24, Environmental Matters, to the Consolidated Financial Statements and Item 1, Business — Environmental Matters, section. NRG discusses details of its regulatory matters in Item 15 — Note 23, Regulatory Matters, to the Consolidated Financial Statements and Item 1, Business — Regulatory Matters, section. NRG discusses details of its legal proceedings in Item 15 — Note 22, Commitments and Contingencies, to the Consolidated Financial Statements. Some of this information relates to costs that may be material to the Company's financial results.

Impact of inflation on NRG's results

Unless discussed specifically in the relevant segment, for the years ended December 31, 2011, 2010 and 2009, the impact of inflation and changing prices (due to changes in exchange rates) on NRG's revenues and net income was immaterial.

Significant events during the year ended December 31, 2011

Results of Operations and Financial Condition

• Lower net income — Net income decreased by 59% from $477 million to $197 million, which reflects a decrease in gross margin for wholesale generation driven by lower realized prices and a decrease in gross margin from the unprecedented heat wave in August 2011 in Texas, which negatively impacted both retail and generation gross margins. In addition, the decrease reflects a $160 million impairment charge on emissions allowances, the $495 million impairment of NRG's investment in Nuclear Innovation North America LLC, or NINA, and a loss on debt extinguishment of $175 million. These amounts were offset in part by a tax benefit of $843 million in 2011, which primarily reflects the impact of the resolution of the federal tax audit in June 2011, compared to tax expense of $277 million in 2010.

• Liquidity position — The Company's total liquidity, excluding collateral received, decreased by $2.2 billion in 2011. Cash balances decreased by $1.8 billion since the end of 2010, primarily due to capital expenditures for solar and other repowering projects, as well as additional share repurchases. In addition, availability under the revolving credit arrangements decreased due to additional letters of credit required for solar and other repowering projects.

• Long-term debt — During 2011, the Company increased its non-recourse debt by approximately $1.0 billion primarily in connection with the financing of the construction of three Utility Scale Solar facilities.

4

Consolidated Results of Operations

2011 compared to 2010

The following table provides selected financial information for the Company:

	Year Ended December 31,
(In millions except otherwise noted)	2011			2010			Change %
Operating Revenues
Energy revenue (a)	$	2,069		$	2,854		(28	)%
Capacity revenue (a)	736			824			(11	)
Retail revenue	5,807			5,277			10
Mark-to-market for economic hedging activities	325			(199		)	263
Contract amortization	(159		)	(195		)	18
Other revenues (b)	301			288			5
Total operating revenues	9,079			8,849			3
Operating Costs and Expenses
Generation cost of sales (a)	2,488			2,170			15
Retail cost of sales (a)	2,815			2,822			—
Mark-to-market for economic hedging activities	169			(111		)	252
Contract and emissions credit amortization (c)	47			15			213
Other cost of operations	1,156			1,177			(2	)
Total cost of operations	6,675			6,073			10
Depreciation and amortization	896			838			7
Impairment charge on emission allowances	160			—			N/A
Selling, general and administrative	668			598			12
Development costs	45			55			(18	)
Total operating costs and expenses	8,444			7,564			12
Gain on sale of assets	—			23			(100	)
Operating Income	635			1,308			(51	)
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	35			44			(20	)
Impairment charge on investment	(495		)	—			N/A
Other income, net	19			33			(42	)
Loss on debt extinguishment	(175		)	(2		)	N/A
Interest expense	(665		)	(630		)	6
Total other expense	(1,281		)	(555		)	131
(Loss)/Income before income tax expense	(646		)	753			(186	)
Income tax (benefit)/ expense	(843		)	277			(404	)
Net Income	197			476			(59	)
Less: Net loss attributable to noncontrolling interest	—			(1		)	100
Net income attributable to NRG Energy, Inc.	$	197		$	477		(59	)
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	4.04			4.39			(8	)%

(a) Includes realized gains and losses from financially settled transactions.

(b) Includes unrealized trading gains and losses.

(c) Includes amortization of SO₂ and NO_x credits and excludes amortization of Regional Greenhouse Gas Initiative, or RGGI, credits.

N/A - Not Applicable

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Management's discussion of the results of operations for the years ended December 31, 2011 and 2010

Conventional Generation gross margin

The following is a discussion of gross margin for NRG's Conventional Generation businesses, adjusted to eliminate intersegment activity primarily with the Retail businesses.

	Year Ended December 31, 2011
	Conventional Generation
(In millions except otherwise noted)	Texas			Northeast			South Central			West			Other			Subtotal			Alternative Energy		Eliminations/Corporate			Consolidated Total
Energy revenue	$	2,545		$	579		$	548		$	31		$	58		$	3,761		$	43	$	(1,735	)	$	2,069
Capacity revenue	28			291			243			118			70			750					(14		)	736
Other revenue	86			26			18			4			196			330			1		(30		)	301
Generation revenue	2,659			896			809			153			324			4,841			$	44	$	(1,779	)	$	3,106
Generation cost of sales	(1,228		)	(527		)	(547		)	(16		)	(186		)	(2,504		)			$	16		$	(2,488	)
Generation gross margin	$	1,431		$	369		$	262		$	137		$	138		$	2,337		$	44
Business Metrics
MWh sold (in thousands)	48,078			9,317			17,131			215									1,263
MWh generated (in thousands)	45,165			7,361			16,000			215									1,263

	Year Ended December 31, 2010
	Conventional Generation
(In millions except otherwise noted)	Texas			Northeast			South Central			West			Other			Subtotal			Alternative Energy		Eliminations/Corporate			Consolidated Total
Energy revenue	$	2,840		$	726		$	387		$	25		$	46		$	4,024		$	39	$	(1,209	)	$	2,854
Capacity revenue	25			396			235			113			71			840					(16		)	824
Other revenue	111			47			10			4			186			358			2		(72		)	288
Generation revenue	2,976			1,169			632			142			303			5,222			$	41	$	(1,297	)	$	3,966
Generation cost of sales	(1,111		)	(493		)	(403		)	(15		)	(166		)	(2,188		)			$	18		$	(2,170	)
Generation gross margin	$	1,865		$	676		$	229		$	127		$	137		$	3,034		$	41
Business Metrics
MWh sold (in thousands)	45,948			10,581			13,046			217									1,030
MWh generated (in thousands)	43,722			9,355			11,168			217									1,030

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	Year Ended December 31,
	Texas	Northeast	South Central	West
Weather Metrics
2011
CDDs (a)	3,440	750	1,817	717
HDDs (a)	1,911	5,770	3,387	3,364
2010
CDDs	2,884	850	2,006	678
HDDs	2,161	5,720	3,929	2,753
30 year average
CDDs	2,647	537	1,548	704
HDDs	1,997	6,257	3,601	3,218

(a) National Oceanic and Atmospheric Administration-Climate Prediction Center — A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.

Conventional Generation gross margin — decreased by $697 million, including intercompany sales, during the year ended December 31, 2011, compared to the same period in 2010, due to:

Decrease in Texas region	$	(434	)
Decrease in Northeast region	(307		)
Increase in South Central region	33
Increase in West region	10
Other	1
	$	(697	)

The decrease in gross margin in the Texas region was driven by:

Lower energy revenue due to a 14% decrease in average realized energy prices, which reflects lower     hedged prices in 2011	$	(315	)
Losses incurred primarily due to hedging and trading optimization activities, and the impact of unplanned outages at gas plants as ERCOT power prices spiked in August 2011	(80		)
Higher coal costs due to a 9% increase in realized coal prices offset by favorable financial fuel hedges	(40		)
Favorable gross margin impact from a 2% increase in coal generation driven by higher economic dispatch and fewer planned outages, partially offset by greater unplanned outages	24
Unfavorable gross margin impact due to a 4% decrease in nuclear generation driven by an increase in unplanned outages	(18		)
Other	(5		)
	$	(434	)

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The decrease in gross margin in the Northeast region was driven by:

Lower gross margin from coal plants due to a 34% decrease in realized energy prices	$	(129	)
Lower gross margin from coal plants resulting from a 30% decrease in generation, due to the region's power generation switching from coal to gas plants as gas prices decreased and due to the retirement of one unit at Indian River	(81		)
Lower capacity revenue due to 10% lower volumes from higher forced outage rates and a 12% decrease in realized prices	(71		)
Lower capacity revenue due to significantly lower LFRM prices and volumes in New England	(27		)
Other	1
	$	(307	)

The increase in gross margin in the South Central region was driven by:

Higher gross margin from merchant energy due to a 155% increase in MWh sold, primarily related to the addition of the Cottonwood facility	$	29
Lower merchant revenue related to a 7% decrease in average realized prices	(18		)
Higher contract revenue from new contracts with three regional municipalities	29
Higher capacity revenue due primarily to higher cooperative billing peaks	8
Higher coal costs due to a 1% increase in generation at the region's coal plant which reflects fewer outage hours in 2011 and a 4% increase in price due to higher transportation costs	(16		)
Other	1
	$	33

The increase in gross margin in the West region was driven by:     

Higher capacity revenue due to additional sales at El Segundo and a price increase on the Cabrillo I tolling agreement	$	5
Increase in other revenue due to fuel oil sales at Encina and financial revenues	6
Other	(1		)
	$	10

Retail gross margin

The Company's Retail business segment is comprised of Reliant Energy, Green Mountain Energy and Energy Plus. The following is a detailed discussion of retail gross margin for NRG's Retail business segment. Green Mountain Energy and Energy Plus were acquired on November 5, 2010 and September 30, 2011, respectively.

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	Year ended December 31
(In millions except otherwise noted)	2011		2010
Operating Revenues
Mass revenues	$	3,545	$	3,127
Commercial and Industrial revenues	2,079		1,994
Supply management revenues	188		158
Retail operating revenues (a)(b)	5,812		5,279
Retail cost of sales (c)	4,558		4,066
Retail gross margin	$	1,254	$	1,213
Business Metrics
Electricity sales volume — GWh
Mass	28,035		22,924
Commercial and Industrial (a)	28,567		26,372
Electricity sales volume — GWh
Texas	55,085		49,261
All other regions	1,517		35
Average retail customers count (in thousands, metered locations)
Mass	2,031		1,815
Commercial and Industrial (a)	85		74
Retail customers count (in thousands, metered locations)
Mass	2,063		1,788
Commercial and Industrial (a)	91		74
Weather Metrics
CDDs (d)	3,845		3,305
HDDs (d)	1,570		1,812

(a) Includes customers of the Texas General Land Office, for whom the Company provides services.

(b) Includes intercompany sales of $5 million and $2 million, representing sales from Retail to the Texas region for the years ended December 31, 2011 and 2010, respectively.

(c) Includes intercompany purchases of $1,743 million and $1,244 million, respectively.

(d) The CDDs/HDDs amounts are representative of the Coast and North Central Zones within the ERCOT market in which Retail serves its customer base.

• Retail gross margin — Retail gross margin increased $41 million for the year ended December 31, 2011, compared to the same period in 2010, driven by:

Reliant Energy:
Unfavorable gross margin impact of an unprecedented heat wave which resulted in high supply costs for incremental weather volume in August 2011, offset in part by the favorable impact of weather in the first six months of 2011	$	(50	)
Favorable volume impact on gross margin of higher average customer usage, offset in part by fewer customers and a change in customer mix	25
Decrease in retail margins of 8% due to lower pricing on acquisitions and renewals consistent with     competitive offers	(42		)
Estimated favorable impact in 2010 as compared to 2011 from the termination of out-of-market supply contracts in conjunction with 2009 CSRA unwind	(68		)
Acquisition of Green Mountain Energy on November 5, 2010	151
Acquisition of Energy Plus on September 30, 2011	25
	$	41

• Trends — Customer counts increased by approximately 104,000 since December 31, 2010, excluding the approximately 188,000 customers acquired in the Energy Plus acquisition, indicating a stabilization of customer attrition at Reliant Energy and customer acquisition efforts at Green Mountain Energy. Higher than normal cooling and heating degree days in both periods resulted in higher customer usage for Reliant Energy of 13% in 2011 and 7% in 2010 when compared to ten-year normal weather.

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Alternative Energy gross margin

NRG's Alternative Energy business segment, which is comprised mainly of the solar and wind businesses, had gross margin of $44 million for the year ended December 31, 2011, compared to gross margin of $41 million for the year ended December 31, 2010. The increase in gross margin primarily resulted from the addition of the Roadrunner facility, which began commercial operations in late 2011.

Mark-to-market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results increased by $244 million in the year ended December 31, 2011, compared to the same period in 2010.

The breakdown of gains and losses included in operating revenues and operating costs and expenses by region are as follows:

	Year Ended December 31, 2011
	Retail			Texas			Northeast			South Central			West			Elimination (a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(1	)	$	(72	)	$	19		$	26		$	(2	)	$	(48	)	$	(78	)
Net unrealized gains/(losses) on open positions related to economic hedges	9			245			9			(38		)	(2		)	180			403
Total mark-to-market gains/(losses) in operating revenues	$	8		$	173		$	28		$	(12	)	$	(4	)	$	132		$	325
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	94		$	—		$	(6	)	$	(4	)	$	—		$	48		$	132
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009	72			—			—			—			—			—			72
Reversal of loss positions acquired as part of the Green Mountain Energy acquisition as of November 5, 2010	35			—			—			—			—			—			35
Net unrealized losses on open positions related to economic hedges	(175		)	(23		)	(17		)	(13		)	—			(180		)	(408		)
Total mark-to-market gains/(losses) in operating costs and expenses	$	26		$	(23	)	$	(23	)	$	(17	)	$	—		$	(132	)	$	(169	)

(a) Represents the elimination of the intercompany activity between the Retail businesses and the Conventional Generation regions and Alternative Energy.

Mark-to-market results consist of unrealized gains and losses. The settlement of these transactions is reflected in the same caption as the items being hedged.

For the year ended December 31, 2011, the $403 million gain in operating revenue from economic hedge positions was primarily driven by an increase in value of forward purchases and sales of natural gas and electricity due to a decrease in forward power and gas prices. The $408 million loss in operating costs and expenses from economic hedge positions was primarily driven by a decrease in value of forward purchases of natural gas, electricity and fuel due to a decrease in forward power and gas prices. Reliant Energy's $72 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of May 1, 2009, and valued using forward prices on that date. These roll-off amounts were offset by realized losses at the settled prices and

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higher costs of physical power which are reflected in operating costs and expenses during the same period. Green Mountain Energy's $35 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of November 5, 2010, and valued using forward prices on that date. These roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in operating costs and expenses during the same period.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the years ended December 31, 2011, and 2010. The realized and unrealized financial and physical trading results are included in operating revenues. The Company's trading activities are subject to limits within the Company's Risk Management Policy.

	Year Ended December 31,
	2011			2010
	(In millions)
Trading gains/(losses)
Realized	$	(31	)	$	(25	)
Unrealized	63			64
Total trading gains	$	32		$	39

Contract Amortization Revenue

Contract amortization represents the roll-off of in-market customer contracts valued under purchase accounting and the favorable change of $36 million as compared to the prior period in 2010 related primarily to lower contract amortization of $74 million for Reliant Energy, offset by higher contract amortization of $29 million for Green Mountain Energy.

Contract and Emissions Credit Amortization

Contract and emissions credit amortization increased primarily due to lower amortization, which is an offset to expense, of out-of-the-money energy supply contracts that were valued as part of the purchase accounting for Reliant Energy.

Other Operating Costs

	Retail		Texas		Northeast		South Central		West		Other		Alternative Energy		Corporate/Eliminations			Total
	(In millions)
Year ended December 31, 2011	$	216	$	477	$	241	$	104	$	56	$	71	$	17	$	(26	)	$	1,156
Year ended December 31, 2010	$	195	$	484	$	287	$	93	$	64	$	68	$	15	$	(29	)	$	1,177

Other operating costs decreased by $21 million for the year ended December 31, 2011, compared to the same period in 2010, due to:

	(In millions)
Decrease in Northeast region operations and maintenance expense	$	(50	)
Increase in Retail operations and maintenance expense	22
Increase in South Central region operations and maintenance expense	6
Other	1
	$	(21	)

11

◦ Northeast operations and maintenance— decreased due to a $19 million reduction in normal and major maintenance, primarily in Western New York, an $18 million decrease in operational labor from headcount reductions at plants in New England and New York, and prior year write-offs of $21 million of construction-in-progress, including those in connection with the early retirement of Indian River Unit 3, and additional write-offs at Arthur Kill, Keystone and Conemaugh.  These were offset in part by the current year write-off of $12 million of Bluewater Wind assets.

◦ Retail operations and maintenance— increased as a result of the acquisition of Green Mountain Energy in November 2010, resulting in a full year of expense compared to two months in the prior year, as well as the acquisition of Energy Plus on September 30, 2011.

◦ South Central operations and maintenance— increased by $18 million due to increased operations and maintenance related to the addition of the Cottonwood Facility, offset in part by $12 million related to the scope and timing of outage work at Big Cajun II in 2010.

Depreciation and Amortization

NRG's depreciation and amortization expense increased by $58 million during the year ended December 31, 2011, compared to the same period in 2010. This was primarily due to additional depreciation related to a full year of depreciation for Cottonwood, Green Mountain Energy, and Northwind Phoenix which were acquired in 2010, as compared to a partial year of depreciation in 2010.

Impairment Charge on Emission Allowances

As described in Item 15 — Note 24, Environmental Matters, to the Consolidated Financial Statements,the Company recorded an impairment charge of $160 million in the year ended December 31, 2011, on the Company's Acid Rain Program SO₂ emission allowances, which were recorded as an intangible asset on the Company's balance sheet. The impairment charge reflects the write-off of the value of emission allowances in excess of those required for compliance with the Acid Rain Program.

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased by $70 million during the year ended December 31, 2011, compared to the same period in 2010, which was primarily due to:

• The acquisition of Green Mountain Energy in November 2010, and the acquisition of Energy Plus in September 2011, which resulted in additional expense in 2011 of $74 million and $16 million, respectively.

• Increased marketing costs of $8 million associated with additional advertising campaigns and sponsorship arrangements.

These increases were offset by:

• A decrease in bad debt expense of $13 million at Reliant Energy due to improved customer payment behavior and decreased revenues.

• A decrease in employee benefits costs of $24 million.

• A reduction in charitable contributions, due to $8 million of funding for the Reliant Energy Charitable Foundation which was created and funded in 2010.

Development Costs

Development costs decreased $10 million during the year ended December 31, 2011, compared to the same period in 2010, as many of the NRG Solar projects are in construction phase in 2011.

Gain on Sale of Assets

On January 11, 2010, NRG sold Padoma to Enel, recognizing a gain on the sale of $23 million.

12

Equity in Earnings of Unconsolidated Affiliates

NRG's equity earnings from unconsolidated affiliates decreased by $9 million during the year ended December 31, 2011, compared to the same period in 2010. The decrease is due primarily to the changes in fair value of Sherbino's forward gas contract of $10 million and a decrease in equity earnings from Gladstone of $15 million, offset by an increase in equity earnings of $10 million from GenConn, as the Devon and Middletown peaking facilities commenced commercial operations in June 2010 and June 2011, respectively, and an increase of $2 million from Saguaro.

Impairment Charge on Investment

As discussed in more detail in Item 15— Note 4, Nuclear Innovation North America LLC Developments, Including Impairment Charge, to the Consolidated Financial Statements, the devastating March 2011 earthquake and tsunami in Japan, which in turn, triggered a nuclear incident at the Fukushima Daiichi Nuclear Power Station, caused NRG to evaluate its investment in NINA for impairment. Consequently, NRG deconsolidated its investment in NINA and recorded an impairment charge in the first quarter equal to the balance of its investment in NINA. In concurrence with a substantial reduction in NINA's project workforce, and to support NINA's reduced scope of work, NRG contributed an additional $14 million into NINA in the year ended December 31, 2011. As a result, NRG recorded an impairment charge of $495 million in the year ended December 31, 2011.

Other Income/(Expense), Net

NRG's other income, net decreased $14 million during the year ended December 31, 2011, compared to the same period in 2010, which relates primarily to foreign exchange gains of $14 million recognized in the prior period.

Loss on Debt Extinguishment

A loss on debt extinguishment of $175 million was recorded in the year ended December 31, 2011, which primarily consisted of the premiums paid on redemption and the write-off of previously deferred financing costs related to the redemptions of the 2014 Senior Notes and the 2016 Senior Notes, and the write-off of previously deferred financing costs related to the replacement of NRG's Senior Credit Facility with the 2011 Senior Credit Facility.

Interest Expense

NRG's interest expense increased by $35 million during the year ended December 31, 2011, compared to the same period in 2010 due to the following:

	(In millions)
Increase/(decrease) in interest expense
Increase for 2020 Senior Notes issued in August 2010	$	58
Increase for 2018 Senior Notes issued in January 2011	85
Increase for 2019 and 2021 Senior Notes issued in May 2011	94
Decrease for 2014 Senior Notes redeemed in January and February 2011	(65		)
Decrease for 2016 Senior Notes redeemed in May and June 2011	(102		)
Increase for project financings	15
Increase for tax-exempt bonds	12
Decrease for refinancing of term loan and revolving credit facility	(18		)
Decrease for capitalized interest	(44		)
Total	$	35

13

Income Tax Expense

There was an income tax benefit of $843 million for the year ended December 31, 2011, compared to income tax expense of $277 million for the year ended December 31, 2010. The effective tax rate was 130.5% and 36.8% for the year ended December 31, 2011, and 2010, respectively.

	Year Ended December 31,
	2011			2010
	(In millions except as otherwise stated)
(Loss)/Income Before Income Taxes	$	(646	)	$	753
Tax at 35%	(226		)	264
State taxes, net of federal benefit	15			18
Foreign operations	(3		)	(3		)
Federal and state tax credits	(1		)	(7		)
Valuation allowance	(63		)	(34		)
Expiration/utilization of capital losses	45			—
Reversal of valuation allowance on expired/utilized capital losses	(45		)	—
Foreign earnings	4			17
Non-deductible interest	—			4
Interest accrued on uncertain tax positions	2			25
Production tax credits	(14		)	(11		)
Reversal of uncertain tax position reserves	(561		)	—
Other	4			4
Income tax (benefit)/expense	$	(843	)	$	277
Effective income tax rate	130.5		%	36.8		%

The effective tax rate for the year ended December 31, 2011 differs from the statutory rate of 35% primarily due to a benefit of $633 million resulting from the resolution of the federal tax audit. The benefit is predominantly due to the recognition of previously uncertain tax benefits that were settled upon audit in 2011 and that were mainly composed of net operating losses of $536 million which had been classified as capital loss carryforwards for financial statement purposes.

The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and changes in valuation allowances in accordance with ASC 740, Income Taxes, or ASC 740. These factors and others, including the Company's history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.

14

Consolidated Results of Operations

2010 compared to 2009

The following table provides selected financial information for the Company:

	Year Ended December 31,
(In millions except otherwise noted)	2010			2009			Change %
Operating Revenues
Energy revenue (a)	$	2,854		$	3,726		(23	)%
Capacity revenue (a)	824			1,023			(19	)
Retail revenue	5,277			4,440			19
Mark-to-market for economic hedging activities	(199		)	(107		)	(86	)
Contract amortization	(195		)	(179		)	(9	)
Other revenues (b)	288			49			488
Total operating revenues	8,849			8,952			(1	)
Operating Costs and Expenses
Generation cost of sales (a)	2,170			1,911			14
Retail cost of sales (a)	2,822			3,121			(10	)
Mark-to-market activities	(111		)	(842		)	(87	)
Contract and emissions credit amortization (c)	15			(4		)	475
Other cost of operations	1,177			1,137			4
Total cost of operations	6,073			5,323			14
Depreciation and amortization	838			818			2
Selling, general and administrative	598			550			9
Acquisition-related transaction and integration costs	—			54			(100	)
Development costs	55			48			15
Total operating costs and expenses	7,564			6,793			11
Gain on sale of assets	23			—			N/A
Operating income	1,308			2,159			(39	)
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	44			41			7
Gain on sale of equity method investments	—			128			(100	)
Other income/(expense), net	33			(5		)	N/A
Loss on debt extinguishment and refinancing expenses	(2		)	(20		)	(90	)
Interest expense	(630		)	(634		)	(1	)
Total other expense	(555		)	(490		)	13
Income before income tax expense	753			1,669			(55	)
Income tax expense	277			728			(62	)
Net Income	476			941			(49	)
Less: Net loss attributable to noncontrolling interest	(1		)	(1		)	—
Net income attributable to NRG Energy, Inc.	$	477		$	942		(49	)
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	4.39			3.92			12	%

(a) Includes realized gains and losses from financially settled transactions.

(b) Includes unrealized trading gains and losses.

(c) Includes amortization of SO₂ and NO_x credits and excludes amortization of Regional Greenhouse Gas Initiative, or RGGI, credits.

N/A - Not Applicable

15

Management's discussion of the results of operations for the years ended December 31, 2010 and 2009

Conventional Generation gross margin

The following is a discussion of gross margin for NRG's Conventional Generation businesses, adjusted to eliminate intersegment activity primarily with the Retail businesses.

	Year Ended December 31, 2010
(In millions except otherwise noted)	Texas			Northeast			South Central			West			Other			Subtotal			Alternative Energy		Eliminations/Corporate			Consolidated Total
Energy revenue	$	2,840		$	726		$	387		$	25		$	46		$	4,024		$	39	$	(1,209	)	$	2,854
Capacity revenue	25			396			235			113			71			840			—		(16		)	824
Other revenue	111			47			10			4			186			358			2		(72		)	288
Generation revenue	2,976			1,169			632			142			303			5,222			$	41	$	(1,297	)	$	3,966
Generation cost of sales	(1,111		)	(493		)	(403		)	(15		)	(166		)	(2,188		)	—		$	18		$	(2,170	)
Generation gross margin	$	1,865		$	676		$	229		$	127		$	137		$	3,034		$	41
Business Metrics
MWh sold (in thousands)	45,948			10,581			13,046			217									1,030
MWh generated (in thousands)	43,722			9,355			11,168			217									1,030

	Year Ended December 31, 2009
(In millions except otherwise noted)	Texas			Northeast			South Central			West			Other			Subtotal			Alternative Energy		Eliminations/Corporate			Consolidated Total
Energy revenue	$	2,762		$	873		$	367		$	26		$	52		$	4,080		$	8	$	(362	)	$	3,726
Capacity revenue	193			407			269			122			79			1,070			—		(47		)	1,023
Other revenue	(57		)	(9		)	(60		)	2			157			33			—		16			49
Generation revenue	2,898			1,271			576			150			288			5,183			$	8	$	(393	)	$	4,798
Generation cost of sales	(909		)	(408		)	(387		)	(29		)	(177		)	(1,910		)	—		$	(1	)	$	(1,911	)
Generation gross margin	$	1,989		$	863		$	189		$	121		$	111		$	3,273		$	8
Business Metrics
MWh sold (in thousands)	46,909			9,220			12,144			1,278									351
MWh generated (in thousands)	44,643			9,220			10,398			1,278									351

16

	Year Ended December 31,
	Texas	Northeast	South Central	West
Weather Metrics
2010
CDDs	2,884	850	2,006	678
HDDs	2,161	5,720	3,929	2,753
2009
CDDs	2,881	475	1,549	908
HDDs	1,890	6,286	3,521	3,105
30 year average
CDDs	2,647	537	1,548	704
HDDs	1,997	6,262	3,604	3,228

Conventional Generation gross margin — decreased by $239 million, including intercompany sales, during the year ended December 31, 2010, compared to the same period in 2009, due to:

Decrease in Texas region	$	(124	)
Decrease in Northeast region	(187		)
Increase in South Central region	40
Increase in West region	6
Other (a)	26
	$	(239	)

(a)     The increase in other gross margin primarily represents revenues from the maintenance services business, which are eliminated in consolidation.

The decrease in gross margin in the Texas region was driven by:

Lower capacity revenue due to a lower proportion of baseload contracts which contain a capacity component	$	(168	)
Increase in unrealized trading activities	119
Higher energy margin driven by 2% higher average realized energy prices which reflect higher hedged prices in 2010	56
Increased coal costs due primarily to increased transportation costs	(61		)
Increase in costs of purchased energy for increased obligations when baseload plants are unavailable and additional purchases for bilateral and toll energy agreements	(61		)
Unfavorable gross margin impact from a 1%reduction in coal generation driven by lower economic dispatch and more unplanned outages, partially offset by fewer planned outages	(16		)
Other	7
	$	(124	)

17

The decrease in gross margin in the Northeast region was driven by:

Lower gross margin from coal plants due to a 30% decrease in realized energy prices	$	(236	)
Lower capacity revenue from the expiration of RMR contracts for Montville, Middletown, and Norwalk	(26		)
Lower capacity revenue due to significantly lower LFRM prices and volumes in New England	(10		)
Higher capacity revenue due to 17% higher prices in the NYISO and PJM markets driven in part by the retirement of the New York Power Authority's Poletti facility in January 2010, offset in part by slightly lower volumes and unfavorable hedges.	26
Lower margin on contract revenue due to a decrease in prices	(27		)
Higher gross margin from oil and gas plants due to a 31% increase in realized energy prices	21
Increase in unrealized trading activities	58
Other	7
	$	(187	)

The increase in gross margin in the South Central region was driven by:

Lower gross margin related to merchant energy due primarily to a decrease in average realized prices and lower volumes	$	(50	)
Higher contract revenue due primarily to the region's cooperative customers from fuel cost pass-through and a new contract with a regional municipality	70
Lower capacity revenue due the expiration of a capacity agreement with a regional utility	(34		)
Increase in unrealized trading activities	68
Higher natural gas costs due primarily to the addition of the Cottonwood facility to the region in 2010	(9		)
Other	(5		)
	$	40

The increase in gross margin in the West region was driven by:     

Higher merchant gross margin from an increase in realized energy prices, offset in part by a decrease in generation	$	13
Lower capacity revenue due to reduced resource adequacy and call option contract sales at El Segundo in 2010 as compared to 2009	(9		)
Other	2
	$	6

18

Retail Gross Margin

The following is a detailed discussion of retail gross margin for NRG's Retail business segment.

Selected Income Statement Data

(In millions except otherwise noted)	Year ended December 31, 2010 (c)		Four months ended April 30, 2010		Eight months ended December 31, 2010 (c)		Eight months ended December 31, 2009
Operating Revenues
Mass revenues	$	3,127	$	903	$	2,224	$	2,597
Commercial and Industrial revenues	1,994		640		1,354		1,592
Supply management revenues	158		56		102		251
Retail operating revenues (a)	5,279		1,599		3,680		4,440
Retail cost of sales (b)	4,066		1,232		2,834		3,531
Retail gross margin	$	1,213	$	367	$	846	$	909
(c) The year ended December 31, 2010 and eight months ended December 31, 2010 include $69 million of revenue and $46 million of cost of sales for Green Mountain Energy, which was acquired on November 5, 2010.
Business Metrics
Electricity sales volume — GWh
Mass	22,924		6,089		16,835		17,152
Commercial and Industrial (a)	26,372		8,268		18,104		20,915
Average retail customers count (in thousands, metered locations)
Mass	1,815		1,519		1,800		1,566
Commercial and Industrial (a)	74		64		73		68
Retail customers count (in thousands, metered locations)
Mass	1,788		1,513		1,788		1,531
Commercial and Industrial (a)	74		64		74		66
Weather Metrics
CDDs (c)	3,305		166		3,139		2,972
HDDs (c)	1,812		1,267		545		699

(a) Includes customers of the Texas General Land Office, for whom the Company provides services.

(b) Includes intercompany purchases from the Texas region of $1,244 million, $293 million, $951 million and $409 million, respectively.

(c) The CDDs/HDDs amounts are representative of the Coast and North Central Zones within the ERCOT market in which Retail serves its customer base.

• Retail gross margin — excluding gross margin of $367 million for the first four months of 2010, Retail gross margin decreased $63 million for the year ended December 31, 2010, compared to the same period in 2009, driven by:

Reliant Energy:
Decrease in retail margins of 12% due to lower lower pricing on acquisitions and renewals and price reductions for certain customer segments.	$	(138	)
Estimated favorable impact in 2010 as compared to 2009 from the termination of out-of-market supply contracts in conjunction with the termination of the Reliant credit sleeve	129
Unfavorable volume impact on gross margin from fewer customers in 2010 as well as a change in customer mix	(60		)
Unfavorable gross margin impact due to a 36% decrease in the margin rate on the incremental weather volumes partially offset by higher volumes in 2010 primarily due to warmer weather in the second and third quarters	(17		)
Acquisition of Green Mountain Energy in November 2010	23
	$	(63	)

19

Alternative Energy gross margin

NRG's Alternative Energy business segment, which is comprised mainly of the solar and wind businesses, had gross margin of $41 million for the year ended December 31, 2010, compared to gross margin of $8 million for the year ended December 31, 2009. The increase in gross margin primarily resulted from an increase in owned wind farm generation as the Langford wind facilities began commercial operations in December 2009 and South Trent was acquired in June 2010. In addition, the Blythe solar facility reached commercial operations in late 2009.

Mark-to-market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results decreased by $823 million in years ended December 31, 2010, compared to the same period in 2009.

The breakdown of gains and losses included in operating revenues and operating costs and expenses by region are as follows:

	Year Ended December 31, 2010
	Retail			Texas			Northeast			South Central			West			Other			Elimination(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(1	)	$	(68	)	$	(108	)	$	2		$	—		$	(2	)	$	11		$	(166	)
Net unrealized gains/(losses) on open positions related to economic hedges	—			125			(36		)	(47		)	(4		)	—			(71		)	$	(33	)
Total mark-to-market (losses)/gains in operating revenues	$	(1	)	$	57		$	(144	)	$	(45	)	$	(4	)	$	(2	)	$	(60	)	$	(199	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(60	)	$	36		$	13		$	17		$	—		$	—		$	(11	)	$	(5	)
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009	223			—			—			—			—			—			—			$	223
Reversal of loss positions acquired as part of the Green Mountain Energy acquisition as of November 5, 2010	13			—			—			—			—			—			—			$	13
Net unrealized (losses)/gains on open positions related to economic hedges	(198		)	(2		)	5			4			—			—			71			(120		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(22	)	$	34		$	18		$	21		$	—		$	—		$	60		$	111

(a) Represents the elimination of the intercompany activity between the Retail businesses and the Conventional Generation regions.

20

Mark-to-market results consist of unrealized gains and losses. The settlement of these transactions is reflected in the same caption as the items being hedged.

For the year ended December 31, 2010, the $33 million loss in operating revenue from economic hedge positions is primarily driven by a decrease in value of forward purchases and sales of natural gas and electricity due to a decrease in forward power and gas prices. The $120 million loss in operating costs and expenses from economic hedge positions is primarily driven by a decrease in value of forward purchases of natural gas, electricity and fuel due to a decrease in forward power and gas prices. Reliant Energy's $223 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of May 1, 2009, and valued using forward prices on that date. These roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in operating costs and expenses during the same period. Green Mountain Energy's $13 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of November 5, 2010, and valued using forward prices on that date. These roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in operating costs and expenses during the same period.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the years ended December 31, 2010, and 2009. The realized and unrealized financial and physical trading results are included in operating revenues. The Company's trading activities are subject to limits within the Company's Risk Management Policy.

	Year Ended December 31,
	2010			2009
	(In millions)
Trading gains/(losses)
Realized	$	(25	)	$	216
Unrealized	64			(183		)
Total trading gains	$	39		$	33

Contract Amortization Revenue

Contract amortization represents the roll-off of in-market customer contracts valued under purchase accounting and the increase of $16 million as compared to the prior period in 2010 related primarily to lower contract amortization of $50 million for Texas offset in part by higher contract amortization for Reliant Energy.

Contract and Emissions Credit Amortization

Contract and emissions credit amortization increased primarily due to lower amortization, which is an offset to expense, in the current year for energy supply contracts that were valued as part of the purchase accounting for Reliant Energy.

Other Operating Costs

	Retail		Texas		Northeast		South Central		West		Other		Alternative Energy		Corporate/Eliminations			Total
	(In millions)
Year ended December 31, 2010	$	195	$	484	$	287	$	93	$	64	$	68	$	15	$	(29	)	$	1,177
Year ended December 31, 2009	$	153	$	509	$	306	$	80	$	63	$	30	$	6	$	(10	)	$	1,137

21

Other operating costs increased $40 million during the year ended December 31, 2010, compared to the same period in 2009, due to:

	(In millions)
Increase due to Reliant Energy for an additional four months of costs in 2010 as compared to 2009	$	49
Decrease in property and other tax expense	(22		)
Increase in South Central operations and maintenance expense	12
Increase in Thermal operations and maintenance expense	6
Decrease in Retail operations and maintenance expense	(9		)
Other	4
	$	40

• Property and other taxes — decreased by $8 million due to a charge in June 2009 to reflect changes in Empire Zone regulations that eliminated the Oswego plant's ability to continue participation in the Empire Zone program and decreased $10 million due to a decrease in gross receipts tax as a result of the decrease in retail revenues.

• South Central operations and maintenance expense — increased by $12 million as the scope and duration of planned maintenance work at the region's coal facility was greater in 2010 than in the same period in 2009.

• Thermal operations and maintenance expense — increase by $6 million relating to the acquisition of Northwind Phoenix in 2010.

• Retail operations and maintenance expense — decreased at Reliant Energy by $11 million due to lower spending for external costs associated with customer activities including the call center, billing, remittance processing, and credit and collections as well as information technology costs associated with those activities, offset in part by an additional $2 million related to the acquisition of Green Mountain Energy.

Depreciation and Amortization

NRG's depreciation and amortization expense increased by $20 million during the year ended December 31, 2010, compared to the same period in 2009. An increase of $26 million was due to depreciation on the baghouse projects in Western New York and additional depreciation at the Cedar Bayou plant, the Langford wind facilities and the Blythe solar facility. Cedar Bayou began commercial operation in June 2009 and the Langford wind facilities began commercial operation in December 2009. An additional increase of $9 million was due to amortization expense at Green Mountain Energy after the date of acquisition.

This increase was offset by a $20 million decrease in depreciation and amortization for Reliant Energy compared to the same period in 2009. Reliant Energy's depreciation and amortization expense decreased $59 million during the eight months ended December 31, 2010 as compared to the same period in 2009, which relates primarily to the amortization expense related to Mass customer relationships valued under purchase accounting which is recognized as the underlying contracts roll off. This decrease at Reliant Energy was offset by $39 million of additional depreciation and amortization expense for the first four months of 2010.

22

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased by $48 million during the year ended December 31, 2010, compared to the same period in 2009. Excluding $68 million of additional expense for Reliant Energy in the first four months of 2010, selling, general and administrative expenses decreased by $20 million, due to:

• A decrease in bad debt expense of $20 million due to decreased revenues and improved customer payment behavior.

• Prior year non-recurring costs related to Exelon's exchange offer and proxy contest efforts of $31 million.

These decreases were offset by:

• Green Mountain Energy's costs of $10 million incurred since the acquisition date.

• The contribution of $8 million in funding for the Reliant Energy Charitable Foundation which was created in 2010.

• An increase in $8 million in professional services for various on-going projects in 2010.

Reliant Energy Acquisition-Related Transaction and Integration Costs

NRG incurred Reliant Energy acquisition-related transaction and integration costs of $54 million for 2009. These integration efforts were completed by the end of 2009.

Development Costs

Development costs increased $7 million during the year ended December 31, 2010, compared to the same period in 2009 due to increased costs incurred primarily on NRG Solar development projects.

Gain on Sale of Assets

On January 11, 2010, NRG sold Padoma to Enel, recognizing a gain on sale of $23 million.

Equity in Earnings of Unconsolidated Affiliates

NRG's equity earnings from unconsolidated affiliates increased by $3 million during the year ended December 31, 2010, compared to the same period in 2009. The 2010 results included increased equity earnings of $15 million from Sherbino, which related to the fair value of a hedge, and $7 million from Gladstone. In 2009, NRG recognized equity earnings of $15 million from MIBRAG, which was sold in June 2009.

Gain on Sale of Equity Method Investments and Other Income/(Loss), Net

NRG's gain on sale of equity method investments in 2009 represents a $128 million gain on the sale of NRG's 50% ownership interest in MIBRAG.

Other Income/(Expense), Net

NRG's other income, net increased $38 million during the year ended December 31, 2010, compared to the same period in 2009 principally due to foreign exchange transactions. The 2010 amount included $5 million and $9 million of unrealized and realized foreign exchange gains, respectively. The 2009 amount included a $24 million loss on a forward contract for foreign currency executed to hedge the sale proceeds from the MIBRAG sale in 2009.

Refinancing Expenses

In 2009, NRG incurred a $20 million expense associated with the CSRA unwind with Merrill Lynch.

23

Interest Expense

NRG's interest expense decreased by $4 million during the year ended December 31, 2010, compared to the same period in 2009 due to the following:

	(In millions)
(Decrease)/increase in interest expense
Increase for 2020 Senior Notes issued in August 2010	$	33
Increase for 2019 Senior Notes issued in June 2009	25
Decrease due to settlement of the CSF Debt in 2009 and early 2010	(26		)
Decrease in fees incurred on the CSRA facility	(27		)
Decrease in capitalized interest	2
Decrease due to Term Loan balance reduction in 2010	(9		)
Other	(2		)
Total	$	(4	)

Income Tax Expense

Income tax expense decreased by $451 million for the year ended December 31, 2010, compared to 2009. The effective tax rate was 36.8% and 43.6% for the year ended December 31, 2010, and 2009, respectively.

	Year Ended December 31,
	2010			2009
	(In millions except as otherwise stated)
Income before income taxes	$	753		$	1,669
Tax at 35%	264			584
State taxes, net of federal benefit	18			23
Foreign operations	(3		)	(53		)
State investment tax credits	(7		)	—
Valuation allowance	(34		)	119
Expiration of capital losses	—			249
Reversal of valuation allowance on expired capital losses	—			(249		)
Change in state effective tax rate	—			(5		)
Foreign earnings	17			33
Non-deductible interest	4			10
Interest on uncertain tax positions	25			9
Production tax credits	(11		)	(10		)
Other	4			18
Income tax expense	$	277		$	728
Effective income tax rate	36.8		%	43.6		%

The Company's effective tax rate differs from the U.S. statutory rate of 35% due to:

• Valuation Allowance — The Company generated capital gains in 2010 primarily due to the derivative contracts that are treated as capital items for tax purposes. The valuation allowance is recorded primarily against capital loss carryforwards, this resulted in an decrease of $34 million in income tax expense in 2010.

• Tax Expense Reduction — The Company recorded a lower federal and state tax expense of $325 million primarily due to lower pre-tax earnings.

• Foreign Operations — In 2010, the Company repatriated foreign dividends to the U.S. resulting in an increase in tax expense of $17 million.

The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and changes in valuation allowances in accordance with ASC 740, Income Taxes, or ASC 740. These factors and others, including the Company's history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.

24

Liquidity and Capital Resources

Liquidity Position

As of December 31, 2011, and 2010, NRG's liquidity, excluding collateral received, was approximately $2.1 billion and $4.3 billion, respectively, comprised of the following:

	As of December 31,
	2011			2010
	(In millions)
Cash and cash equivalents	$	1,105		$	2,951
Funds deposited by counterparties	258			408
Restricted cash	292			8
Total	1,655			3,367
2011 Revolving Credit Facility availability	673			—
Funded Letter of Credit Facility availability	—			440
Revolving Credit Facility availability	—			853
Total liquidity	2,328			4,660
Less: Funds deposited as collateral by hedge counterparties	(258		)	(408		)
Total liquidity, excluding collateral received	$	2,070		$	4,252

For the year ended December 31, 2011, total liquidity, excluding collateral received, decreased by $2.2 billion due primarily to $1.8 billion lower cash and cash equivalent balances. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading CashFlow Discussion. Cash and cash equivalents and funds deposited by counterparties at December 31, 2011, were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.

Included in restricted cash is $216 million of cash and cash equivalents held in controlled accounts as collateral to support the Company's equity funding obligations for the Ivanpah, Agua Caliente, and CVSR projects. As discussed more fully in Item 15 — Note 3, Business Acquisitions and Disposition, to the Consolidated Financial Statements, this is a requirement of the U.S. DOE, which guarantees the Agua Caliente, Ivanpah, and CVSR debt.  This collateral can be replaced, at the Company's discretion, with a letter of credit in order to utilize such amounts for other purposes.  The Company's total liquidity excluding such amounts is $1.9 billion.

The line item "Funds deposited by counterparties" represents the amounts that are held by NRG as a result of collateral posting obligations from the Company's counterparties due to positions in the Company's hedging program. 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. Depending on market fluctuation and the settlement of the underlying contracts, the Company will refund this collateral to the counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities.

As discussed more fully in Item 15— Note 12, Debt and Capital Leases, to the Consolidated Financial Statements, to this Form 10-K, on July 1, 2011, NRG replaced its Senior Credit Facility, consisting of its Term Loan Facility, Revolving Credit Facility and Funded Letter of Credit Facility, with the 2011 Senior Credit Facility, which includes the 2011 Revolving Credit Facility.

Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's preferred stockholders, and other liquidity commitments. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.

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Credit Ratings

Credit rating agencies rate a firm's public debt securities. These ratings are utilized by the debt markets in evaluating a firm's credit risk. Ratings influence the price paid to issue new debt securities by indicating to the market the Company's ability to pay principal, interest and preferred dividends. Rating agencies evaluate a firm's industry, cash flow, leverage, liquidity, and hedge profile, among other factors, in their credit analysis of a firm's credit risk.

The following table summarizes the credit ratings for NRG Energy, Inc., its 2011 Term Loan Facility and its Senior Notes as of December 31, 2011:

	S&P	Moody's	Fitch
NRG Energy, Inc.	BB-	Ba3	B+
7.875% Senior Notes, due 2021	BB-	B1	BB
8.25% Senior Notes, due 2020	BB-	B1	BB
7.625% Senior Notes, due 2019	BB-	B1	BB
8.5% Senior Notes, due 2019	BB-	B1	BB
7.625% Senior Notes, due 2018	BB-	B1	BB
7.375% Senior Notes, due 2017	BB-	B1	BB
Term Loan Facility, due 2018	BB+	Baa3	BB+

Sources of Liquidity

The principal sources of liquidity for NRG's future operating and capital expenditures are expected to be derived from new and existing financing arrangements, existing cash on hand and cash flows from operations. As described in Item 15 — Note 12, Debt and Capital Leases, to the Consolidated Financial Statements, the Company's financing arrangements consist mainly of the 2011 Senior Credit Facility, the Senior Notes, and project-related financings.

In addition, NRG has granted first liens to certain counterparties on substantially all of the Company's assets. NRG uses the first lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. To the extent that the underlying hedge positions for a counterparty are in-the-money to NRG, the counterparty would have no claim under the lien program. The lien program limits the volume that can be hedged, not the value of underlying out-of-the-money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure. Within the first lien structure, the Company can hedge up to 80% of its baseload capacity and 10% of its non-baseload assets with these counterparties for the first 60 months and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.

The Company's lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of December 31, 2011, all hedges under the first liens were in-the-money on a counterparty aggregate basis.

The following table summarizes the amount of MWs hedged against the Company's baseload assets and as a percentage relative to the Company's baseload capacity under the first lien structure as of December 31, 2011:

Equivalent Net Sales Secured by First Lien Structure (a)	2012		2013		2014		2015
In MW (b)	1,268		464		127		—
As a percentage of total net baseload capacity (c)	19	%	7	%	2	%	—	%

(a) Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region.

(b) 2012 MW value consists of February through December positions only.

(c) Net baseload capacity under the first lien structure represents 80% of the Company's total baseload assets.

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Uses of Liquidity

The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercial operations activities; (ii) debt service obligations, as described more fully in Item 15 — Note 12, Debt and Capital Leases, to the Consolidated Financial Statements; (iii) capital expenditures, including repowering and renewable development, and environmental; and (iv) corporate financial transactions including return of capital to stockholders, as described in Item 15 — Note 15, Capital Structure, to the Consolidated Financial Statements.

Commercial Operations

NRG's commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (i.e. buying fuel before receiving energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of December 31, 2011, commercial operations had total cash collateral outstanding of $311 million, and $715 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions (includes a $51 million letter of credit relating to deposits at the PUCT that cover outstanding customer deposits and residential advance payments). As of December 31, 2011, total collateral held from counterparties was $258 million in cash, and $12 million of letters of credit.

Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependent on NRG's credit ratings and general perception of its creditworthiness.

27

Debt Service Obligations

Principal payments on debt and capital leases as of December 31, 2011, are due in the following periods:

Description	2012		2013		2014		2015		2016		Thereafter		Total
	(In millions)
NRG Recourse Debt:
7.875% Notes due 2021	$	—	$	—	$	—	$	—	$	—	$	1,200	$	1,200
8.25% Notes due 2020	—		—		—		—		—		1,100		1,100
7.625% Notes due 2019	—		—		—		—		—		800		800
8.5% Notes due 2019	—		—		—		—		—		700		700
7.625% Notes due 2018	—		—		—		—		—		1,200		1,200
7.375% Notes due 2017	—		—		—		—		—		1,090		1,090
Term Loan Facility, due 2018	16		16		16		16		16		1,512		1,592
Indian River Power LLC, tax-exempt bonds, due 2040 and 2045	—		—		—		—		—		205		205
Dunkirk Power LLC, tax-exempt bonds, due 2042	—		—		—		—		—		59		59
Subtotal NRG Recourse Debt	16		16		16		16		16		7,866		7,946
NRG Non-Recourse Debt:
Ivanpah Financing:
Solar Partners I, due 2014 and 2033	—		—		154		5		6		125		290
Solar Partners II, due 2014 and 2038	—		—		128		5		6		175		314
Solar Partners VIII, due 2014 and 2038	—		—		111		4		4		151		270
NRG Peaker Finance Co. LLC, bonds, due 2019	22		23		29		31		33		72		210
Agua Caliente Solar, LLC	—		—		5		5		6		165		181
NRG West Holdings LLC, term loan, due 2023	—		—		32		37		41		49		159
NRG Energy Center Minneapolis LLC, senior secured notes, due 2013, 2017 and 2025	13		10		7		12		12		96		150
South Trent Wind LLC, due 2020	3		3		4		4		4		57		75
Solar Power Partners Financing	10		9		5		4		3		38		69
NRG Roadrunner LLC, due 2031	14		2		2		2		3		38		61
NRG Solar Blythe LLC, due 2028	2		2		1		2		1		19		27
Other	5		4		—		—		—		—		9
Subtotal NRG Non-Recourse Debt	69		53		478		111		119		985		1,815
Capital Lease:
Saale Energie GmbH, Schkopau	8		7		6		6		4		72		103
Total Debt and Capital Leases	$	93	$	76	$	500	$	133	$	139	$	8,923	$	9,864

In addition to the debt and capital leases shown in the preceding table, NRG had issued $1.627 billion of letters of credit under the Company's $2.3 billion 2011 Revolving Credit Facility as of December 31, 2011.

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Capital Expenditures

The following tables and descriptions summarize the Company's capital expenditures, including accruals, for maintenance, environmental, and repowering and renewable development, other than cash paid for nuclear development, for the year ended December 31, 2011, and the estimated capital expenditure and repowering and renewable investments forecast for 2012. 

	Maintenance			Environmental			Repowering and Renewables			Total
	(In millions)
Northeast	$	21		$	167		$	—		$	188
Texas	99			—			—			99
South Central	23			2			—			25
West	18			—			252			270
Other Conventional	8			—			32			40
Alternative Energy	—			—			1,820			1,820
Retail	23			—			—			23
Corporate	17			—			24			41
Total capital expenditures for the year ended December 31, 2011	209			169			2,128			2,506
Accrual impact	(9		)	20			(227		)	(216		)
Total cash capital expenditures for the year ended December 31, 2011	200			189			1,901			2,290
Other investments (a)	—			—			621			621
Funding from debt financing, net of fees	—			(138		)	(1,215		)	(1,353		)
Funding from third party equity partners	—			—			(29		)	(29		)
Total capital expenditures and investments, net	$	200		$	51		$	1,278		$	1,529
Estimated capital expenditures for 2012	$	259		$	54		$	3,200		$	3,513
Other investments (b)	—			—			(172		)	(172		)
Funding from debt financing, net of fees	—			(61		)	(2,452		)	(2,513		)
Funding from third party equity partners	—			—			(192		)	(192		)
NRG estimated capital expenditures for 2012, net of financings	$	259		$	(7	)	$	384		$	636

(a) 2011 Other investments includes initial investments in the Agua Caliente, Ivanpah and Distributed Solar projects; solar project reserves that are placed in restricted cash on the balance sheet; and other project costs.

(b) 2012 Other investments represents the use of project reserves previously placed in restricted cash on the balance sheet and other project costs.

• Repowering and Renewable capital expenditures — For the year ended December 31, 2011, the Company's repowering and renewable capital expenditures included $1.8 billion for solar projects and $252 million for the Company's El Segundo project. In 2012, NRG will be continuing its efforts on the solar and El Segundo projects.

• Maintenance and Environmental capital expenditures — For the year ended December 31, 2011, the Company's maintenance capital expenditures includes $51 million in nuclear fuel expenditures related to STP Units 1 and 2. The environmental capital expenditures includes $155 million related to a project to install selective catalytic reduction systems, scrubbers and fabric filters on Indian River Unit 4. The system was operational at year-end 2011 and is undergoing performance testing.

29

Environmental Capital Expenditures Estimate

Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures from 2012 through 2016 to meet NRG's environmental commitments will be approximately $553 million. These costs are primarily associated with mercury controls to satisfy MATS on the Company's Big Cajun II, W.A. Parish and Limestone facilities and a number of intake modification projects across the fleet under state or proposed federal 316(b) rules. NRG continues to explore cost effective compliance alternatives to reduce costs. While this estimate reflects anticipated schedules and controls related to the proposed 316(b) Rule, the full impact on the scope and timing of environmental retrofits from any new or revised regulations cannot be determined until these rules are final and any legal challenges are reviewed. However, NRG believes it is positioned to meet more stringent requirements through its planned capital expenditures, existing controls, and increasing generation from renewable resources.

The table below summarizes installed and planned air quality controls for the NRG coal fleet. Planned investments are either in construction or budgeted in the existing capital expenditures budget. Changes to regulations could result in changes to planned installation dates. NRG uses an integrated approach to fuels, controls and emissions markets to meet environmental standards.

	SO2		NOx		Mercury		Particulate
Units	Control Equipment	Install Date	Control Equipment	Install Date	Control Equipment	Install Date	Control Equipment	Install Date
Huntley 67	DSI/FF	2009	SNCR	2009	ACI	2009	FF	2009
Huntley 68	DSI/FF	2009	SNCR	2009	ACI	2009	FF	2009
Dunkirk 1	DSI/FF	2010	SNCR	2010	ACI	2010	FF	2010
Dunkirk 2	DSI/FF	2010	SNCR	2010	ACI	2010	FF	2010
Dunkirk 3	DSI/FF	2009	SNCR	2009	ACI	2009	FF	2009
Dunkirk 4	DSI/FF	2009	SNCR	2009	ACI	2009	FF	2009
Indian River 3			SNCR	2000	ACI	2008	ESP	1980
Indian River 4	Circulating Dry Scrubber	2011	SCR	2011	ACI	2008	ESP/FF	1980 / 2011
Big Cajun II 1	FF co-benefit	2015	LNBOFA	2005	ACI	2015	ESP/FF	1981 / 2015
Big Cajun II 2			LNBOFA	2004	ACI	2015	ESP	1981
Big Cajun II 3	FF co-benefit	2015	LNBOFA	2002	ACI	2015	ESP/FF	1983 / 2015
Limestone 1 & 2	Wet Scrubbers	1985-86	LNBOFA/ SNCR	2002 / 2014	ACI	2014	ESP	1985-86
WA Parish 5, 6, 7	FF co-benefit	1988	SCR	2004	ACI	2014	FF	1988
WA Parish 8	Wet Scrubber	1982	SCR	2004	ACI	2014	FF	1988

ACI —  Activated Carbon Injection

DSI — Dry Sorbent Injection with Trona

ESP — Electrostatic Precipitator

FF— Fabric Filter

LNBOFA — Low NO_x Burner with Overfire Air

SCR — Selective Catalytic Reduction

SNCR — Selective Non-Catalytic Reduction

The following table summarizes the estimated environmental capital expenditures for the referenced periods by region:

	Texas		Northeast		South Central		Total
	(in millions)
2012	$	4	$	45	$	8	$	57
2013	35		16		93		144
2014	48		20		172		240
2015	9		3		92		104
2016	7		1		—		8
Total	$	103	$	85	$	365	$	553

30

NRG's current contracts with the Company's rural electrical customers in the South Central region allow for recovery of a portion of the regions' capital costs once in operation, along with a capital return incurred by complying with any change in law, including interest over the asset life of the required expenditures. The actual recoveries will depend, among other things, on the timing of the completion of the capital projects and the remaining duration of the contracts.

2011 Capital Allocation Program

On February 22, 2011, the Company announced its 2011 Capital Allocation Plan to purchase $180 million in common stock. On August 4, 2011, the Company announced additional share repurchases of $250 million under the Capital Allocation Plan, bringing the total targeted share repurchases for 2011 to $430 million. During 2011, the Company repurchased 14,875,798 shares of NRG common stock for $320 million under two separate Accelerated Share Repurchase, or ASR, Agreements, and purchased an additional 5,099,856 shares for $110 million in open market purchases. The Company's share repurchases are subject to market prices, financial restrictions under the Company's debt facilities and securities laws.

As part of the 2011 program, the Company invested approximately $389 million in maintenance and environmental capital expenditures in existing assets, and approximately $2.5 billion in solar and other projects under development. In 2011, the Company obtained U.S. DOE loan guarantees for its Ivanpah, Agua Caliente, and CVSR solar projects in the amounts of $1.6 billion, $967 million, and $1.2 billion, respectively.

Finally, in addition to scheduled debt amortization payments, in the first quarter 2011 the Company paid its first lien lenders $149 million of its 2010 excess cash flow, as defined in the Senior Credit Facility.

2012 Capital Allocation Program

On February 28, 2012, the Company announced its intention to initiate an annual common stock dividend of $0.36 per share, with the first quarterly payment expected to be paid in the third quarter of 2012.  Furthermore, the Company still intends to refinance its remaining $1.1 billion of 2017 Senior Notes to simplify its capital structure and better align covenant packages, but any refinancing will depend on market conditions and is therefore subject to change. Upon completion of this undertaking, a more flexible covenant package across credit facilities and debt securities will enable NRG to invest more opportunistically in growth initiatives and enhance its ability to efficiently return capital to all stockholders.

Preferred Stock Dividend Payments

For the year ended December 31, 2011, NRG paid $9 million in dividend payments to holders of the Company's 3.625% Preferred Stock.

Cash Flow Discussion

The following table reflects the changes in cash flows for the comparative years:

(In millions)
Year ended December 31,	2011			2010			Change
Net cash provided by operating activities	$	1,166		$	1,623		$	(457	)
Net cash used by investing activities	(3,047		)	(1,623		)	(1,424		)
Net cash provided by financing activities	33			651			(618		)

Net Cash Provided By Operating Activities

Changes to net cash provided by operating activities were driven by:

Decrease in operating income adjusted for non-cash charges	$	(454	)
Other changes in working capital	(3		)
	$	(457	)

31

Net Cash Used By Investing Activities

Changes to net cash used by investing activities were driven by:

Increase in capital expenditures due to increased spending on maintenance, repowering and renewable development, primarily for solar projects in construction	$	(1,604	)
Increase in restricted cash, which was mainly to support equity requirements for     U.S. DOE funded projects	(246		)
Lower cash spent for acquisitions, which primarily reflects three Solar acquisitions and Energy Plus in 2011, compared to Green Mountain, South Trent, Northwind Phoenix and Cottonwood in 2010	629
Decrease in purchases and sales of emissions allowances	15
Decrease in cash for sale of assets, which primarily reflects sale of land in 2011, compared to the sale of Padoma in 2010	(36		)
Receipt of cash grants in 2010	(102		)
Investments in unconsolidated affiliates, primarily related to investments in a clean technology joint venture and Petra Nova	(43		)
Other	(37		)
	$	(1,424	)

Net Cash Provided By Financing Activities

Changes in net cash provided by financing activities were driven by:

Increase in cash paid to repurchase shares of NRG common stock	$	(250	)
Increase in net cash paid/received for the settlement of acquired derivatives with financing elements	(220		)
Increase in cash paid for debt issuance and hedging costs	(132		)
Net increase in cash received for proceeds for issuance of long-term debt	4,740
Net increase in the payments of debt, primarily related to payment of secured Senior Notes	(4,735		)
Decrease in cash contributions from noncontrolling interest	(21		)
	$	(618	)

32

NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740

As of December 31, 2011, the Company had a total domestic pre-tax book loss of $680 million and foreign pre-tax book income of $34 million. For the year ended December 31, 2011, the Company generated a net operating loss, or NOL, of $30 million which is available to offset taxable income in future periods. As of December 31, 2011, the Company has cumulative domestic NOL carryforwards of $233 million for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $255 million, of which $77 million will expire starting 2012 through 2019 and of which $178 million do not have an expiration date.

In addition to these amounts, the Company has $178 million of tax effected uncertain tax benefits. As a result of the Company's tax position, and based on current forecasts, NRG anticipates income tax payments, primarily due to foreign, state and local jurisdictions, of up to $50 million in 2012.

However, as the position remains uncertain for the $178 million of tax effected uncertain tax benefits, the Company has recorded a non-current tax liability of $58 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The $58 million non-current tax liability for uncertain tax benefits is primarily from positions taken on various state returns, including accrued interest.

During 2011, the Company settled the Internal Revenue Service's audit examination for the years 2004 through 2006 and recognized a benefit of $633 million. The benefit is predominantly due to the recognition of previously uncertain tax benefits mainly composed of net operating losses of $536 million which had been classified as capital loss carryforwards for financial statement purposes.

The Company continues to be under examination for various state jurisdictions for multiple years.

Off-Balance Sheet Arrangements

Obligations under Certain Guarantee Contracts

NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. See also Item 15 — Note 26, Guarantees, to the Consolidated Financial Statements for additional discussion.

Retained or Contingent Interests

NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.

Derivative Instrument Obligations

The Company's 3.625% Preferred Stock includes a feature which is considered an embedded derivative per ASC 815. Although it is considered an embedded derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to ASC 815. As of December 31, 2011, based on the Company's stock price, the embedded derivative was out-of-the-money and had no redemption value. See also Item 15 — Note 15, Capital Structure, to the Consolidated Financial Statements for additional discussion.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in Equity investments — As of December 31, 2011, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. Several of these investments are variable interest entities for which NRG is not the primary beneficiary.

33

NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $244 million as of December 31, 2011. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Item 15 — Note 16, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Consolidated Financial Statements for additional discussion.

Contractual Obligations and Commercial Commitments

NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs. The following tables summarize NRG's contractual obligations and contingent obligations for guarantee. See also Item 15 — Note 12, Debt and Capital Leases, Note 22, Commitments and Contingencies, and Note 26, Guarantees, to the Consolidated Financial Statements for additional discussion.

	By Remaining Maturity at December 31,
	2011
Contractual Cash Obligations	Under 1 Year		1-3 Years		3-5 Years		Over 5 Years		Total (a)		2010 Total
	(In millions)
Long-term debt and funded letter of credit (including estimated interest)	$	708	$	1,793	$	1,513	$	10,639	$	14,653	$	14,340
Capital lease obligations (including estimated interest)	11		18		12		82		123		133
Operating leases	67		125		106		280		578		508
Fuel purchase and transportation obligations (b)	891		266		204		484		1,845		1,761
Fixed purchased power commitments	37		32		18		9		96		370
Pension minimum funding requirement (c)	37		90		98		89		314		191
Other postretirement benefits minimum funding requirement (d)	4		7		9		18		38		22
Other liabilities (e)	54		85		66		280		485		697
Total	$	1,809	$	2,416	$	2,026	$	11,881	$	18,132	$	18,022

(a) Excludes $57 million non-current payable relating to NRG's uncertain tax benefits under ASC 740 as the period of payment cannot be reasonably estimated. Also excludes $443 million of asset retirement obligations which are discussed in Item 15 — Note 13, Asset Retirement Obligations, to the Consolidated Financial Statements.

(b) Includes only those coal transportation and lignite commitments for 2012 as no other nominations were made as of December 31, 2011. Natural gas nomination is through February 2016.

(c) These amounts represent the Company's estimated minimum pension contributions required under the Pension Protection Act of 2006. These amounts represent estimates that are based on assumptions that are subject to change.

(d) These amounts represent estimates that are based on assumptions that are subject to change. The minimum required contribution for years after 2019 are currently not available.

(e) Includes water right agreements, service and maintenance agreements, stadium naming rights and other contractual obligations.

	By Remaining Maturity at December 31,
	2011
Guarantees	Under 1 Year		1-3 Years		3-5 Years		Over 5 Years		Total		2010 Total
	(In millions)
Letters of credit and surety bonds	$	1,562	$	108	$	—	$	—	$	1,670	$	887
Asset sales guarantee obligations	60		—		567		8		635		1,022
Commercial sales arrangements	91		100		91		1,123		1,405		1,285
Other guarantees	1		—		—		460		461		171
Total guarantees	$	1,714	$	208	$	658	$	1,591	$	4,171	$	3,365

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Fair Value of Derivative Instruments

NRG may enter into long-term power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at generation facilities or retail load obligations. In addition, in order to mitigate interest rate risk associated with the issuance of the Company's variable rate and fixed rate debt, NRG enters into interest rate swap agreements.

NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at December 31, 2011, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at December 31, 2011. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Item 15 — Note 5, Fair Value of Financial Instruments, to the Consolidated Financial Statements.

Derivative Activity Gains/(Losses)	(In millions)
Fair value of contracts as of December 31, 2010	$	672
Contracts realized or otherwise settled during the period	(395		)
Changes in fair value	174
Fair value of contracts as of December 31, 2011	$	451

	Fair Value of Contracts as of December 31, 2011
Fair value hierarchy Gains/(Losses)	Maturity Less Than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years			Maturity in Excess 4-5 Years			Total Fair Value
	(In millions)
Level 1	$	(36	)	$	(52	)	$	(8	)	$	—		$	(96	)
Level 2	493			80			(20		)	(14		)	539
Level 3	8			—			—			—			8
Total	$	465		$	28		$	(28	)	$	(14	)	$	451

The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 7A — Commodity Price Risk, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using Value at Risk, or VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative assets and liability position is a better indicator of NRG's hedging activity. As of December 31, 2011, NRG's net derivative asset was $451 million, a decrease to total fair value of $221 million as compared to December 31, 2010. This decrease was primarily driven by the roll off of contracts that settled during the period offset by an increase in fair value due to the decreases in gas and power prices.

Based on a sensitivity analysis using simplified assumptions, the impact of a $1 per MMBtu increase or decrease in natural gas prices across the term of the derivative contracts would cause a change of approximately $35 million in the net value of derivatives as of December 31, 2011.

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Critical Accounting Policies and Estimates

NRG's discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the U.S, or U.S. GAAP. The preparation of these financial statements and related disclosures in compliance with U.S. GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies have not changed.

On an ongoing basis, NRG evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.

NRG's significant accounting policies are summarized in Item 15 — Note 2, Summary of Significant Accounting Policies, to the Consolidated Financial Statements. The Company identifies its most critical accounting policies as those that are the most pervasive and important to the 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 about matters that are inherently uncertain.

Accounting Policy	Judgments/Uncertainties Affecting Application
Derivative Instruments	Assumptions used in valuation techniques
	Assumptions used in forecasting generation
	Market maturity and economic conditions
	Contract interpretation
	Market conditions in the energy industry, especially the effects of price volatility on contractual commitments
Income Taxes and Valuation Allowance for Deferred Tax Assets	Ability to withstand legal challenges of tax authority decisions or appeals
	Anticipated future decisions of tax authorities
	Application of tax statutes and regulations to transactions
	Ability to utilize tax benefits through carry backs to prior periods and carry forwards to future periods
Impairment of Long Lived Assets	Recoverability of investment through future operations
	Regulatory and political environments and requirements
	Estimated useful lives of assets
	Environmental obligations and operational limitations
	Estimates of future cash flows
	Estimates of fair value
	Judgment about triggering events
Goodwill and Other Intangible Assets	Estimated useful lives for finite-lived intangible assets
	Judgment about impairment triggering events
	Estimates of reporting unit's fair value
	Fair value estimate of intangible assets acquired in business combinations
Contingencies	Estimated financial impact of event(s)
	Judgment about likelihood of event(s) occurring
	Regulatory and political environments and requirements

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Derivative Instruments

The Company follows the guidance of ASC 815 to account for derivative instruments. ASC 815 requires the Company to mark-to-market all derivative instruments on the balance sheet, and recognize changes in the fair value of non-hedge derivative instruments immediately in earnings. In certain cases, NRG may apply hedge accounting to the Company's derivative instruments. The criteria used to determine if hedge accounting treatment is appropriate are: (i) the designation of the hedge to an underlying exposure; (ii) whether the overall risk is being reduced; and (iii) if there is a correlation between the changes in fair value of the derivative instrument and the underlying hedged item. Changes in the fair value of derivatives instruments accounted for as hedges are either recognized in earnings as an offset to the changes in the fair value of the related hedged item, or deferred and recorded as a component of Other Comprehensive Income, or OCI, and subsequently recognized in earnings when the hedged transactions occur.

For purposes of measuring the fair value of derivative instruments, NRG uses quoted exchange prices and broker quotes. When external prices are not available, NRG uses internal models to determine the fair value. These internal models include assumptions of the future prices of energy commodities based on the specific market in which the energy commodity is being purchased or sold, using externally available forward market pricing curves for all periods possible under the pricing model. In order to qualify derivative instruments for hedged transactions, NRG estimates the forecasted generation occurring within a specified time period. Judgments related to the probability of forecasted generation occurring are based on available baseload capacity, internal forecasts of sales and generation, and historical physical delivery on similar contracts. The probability that hedged forecasted generation will occur by the end of a specified time period could change the results of operations by requiring amounts currently classified in OCI to be reclassified into earnings, creating increased variability in the Company's earnings. These estimations are considered to be critical accounting estimates.

Certain derivative instruments that meet the criteria for derivative accounting treatment also qualify for a scope exception to derivative accounting, as they are considered to be Normal Purchase Normal Sale, or NPNS. The availability of this exception is based upon the assumption that NRG has the ability and it is probable to deliver or take delivery of the underlying item. These assumptions are based on available baseload capacity, internal forecasts of sales and generation and historical physical delivery on contracts. Derivatives that are considered to be NPNS are exempt from derivative accounting treatment, and are accounted for under accrual accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception due to changes in estimates, the related contract would be recorded on the balance sheet at fair value combined with the immediate recognition through earnings.

Income Taxes and Valuation Allowance for Deferred Tax Assets

As of December 31, 2011, NRG had a valuation allowance of $83 million. This amount is comprised of foreign net operating loss carryforwards of $71 million, foreign capital loss carryforwards of approximately $1 million and U.S. domestic state NOLs of $11 million. In assessing the recoverability of NRG's deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is primarily dependent upon earnings in foreign jurisdictions.

NRG continues to be under audit for multiple years by taxing authorities in other jurisdictions. Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws. NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Germany and Australia. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2007. With few exceptions, state and local income tax examinations are no longer open for years before 2003. The Company's significant foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2004.

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Evaluation of Assets for Impairment and Other Than Temporary Decline in Value

In accordance with ASC 360, Property, Plant, and Equipment, or ASC 360, NRG evaluates property, plant and equipment and certain intangible assets for impairment whenever indicators of impairment exist. Examples of such indicators or events are:

• Significant decrease in the market price of a long-lived asset;

• Significant adverse change in the manner an asset is being used or its physical condition;

• Adverse business climate;

• Accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset;

• Current-period loss combined with a history of losses or the projection of future losses; and

• Change in the Company's intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life.

Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power pool prices, escalated future project operating costs and expected plant operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the probability weighting of different courses of action available to the Company. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. NRG uses its best estimates in making these evaluations and considers various factors, including forward price curves for energy, fuel costs and operating costs. However, actual future market prices and project costs could vary from the assumptions used in the Company's estimates, and the impact of such variations could be material.

For assets to be held and used, if the Company determines that the undiscounted cash flows from the asset are less than the carrying amount of the asset, NRG must estimate fair value to determine the amount of any impairment loss. Assets held-for-sale are reported at the lower of the carrying amount or fair value less the cost to sell. The estimation of fair value under ASC 360, whether in conjunction with an asset to be held and used or with an asset held-for-sale, and the evaluation of asset impairment are, by their nature, subjective. NRG considers quoted market prices in active markets to the extent they are available. In the absence of such information, the Company may consider prices of similar assets, consult with brokers, or employ other valuation techniques. NRG will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment or employ an expected present value method that probability-weights a range of possible outcomes. The use of these methods involves the same inherent uncertainty of future cash flows as previously discussed with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in the Company's estimates, and the impact of such variations could be material.

NRG is also required to evaluate its equity-method and cost-method investments to determine whether or not they are impaired. ASC 323, Investments - Equity Method and Joint Ventures, or ASC 323, provides the accounting requirements for these investments. The standard for determining whether an impairment must be recorded under ASC 323 is whether the value is considered an "other than a temporary" decline in value. The evaluation and measurement of impairments under ASC 323 involves the same uncertainties as described for long-lived assets that the Company owns directly and accounts for in accordance with ASC 360. Similarly, the estimates that NRG makes with respect to its equity and cost-method investments are subjective, and the impact of variations in these estimates could be material. Additionally, if the projects in which the Company holds these investments recognize an impairment under the provisions of ASC 360, NRG would record its proportionate share of that impairment loss and would evaluate its investment for an other than temporary decline in value under ASC 323.

Goodwill and Other Intangible Assets

At December 31, 2011, NRG reported goodwill of $1.9 billion, consisting of $1.7 billion in its Texas operating segment, or NRG Texas, that is associated with the acquisition of Texas Genco in 2006, and $144 million and $29 million in its corporate operating segment that is associated with the acquisition of Green Mountain Energy in November 2010 and Energy Plus in September 2011, respectively. The Company has also recorded intangible assets in connection with its business acquisitions, measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined in ASC 820. See Item 15 — Note 3, Business Acquisitions and Dispositions, and Note 11, Goodwill and Other Intangibles, to the Consolidated Financial Statements for further discussion.

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The Company applies ASC 805, Business Combinations, or ASC 805, and ASC 350, to account for its goodwill and intangible assets. Under these standards, the Company amortizes all finite-lived intangible assets over their respective estimated weighted-average useful lives, while goodwill has an indefinite life and is not amortized. However, goodwill and all intangible assets not subject to amortization are tested for impairments at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The Company tests goodwill for impairment at the reporting unit level, which is identified by assessing whether the components of the Company's operating segments constitute businesses for which discrete financial information is available and whether segment management regularly reviews the operating results of those components. The Company performs the annual goodwill impairment assessment as of December 31 or when events or changes in circumstances indicate that the carrying value may not be recoverable. In 2011, NRG adopted the provisions of ASU 2011-08, Intangibles - Goodwill and Other (Topic 350) Testing Goodwill for Impairment, or ASU 2011-08, which allows the consideration of qualitative factors to determine if it is more likely than not that impairment has occurred. In the absence of sufficient qualitative factors, goodwill impairment is determined utilizing a two-step process. If it is determined that the fair value of a reporting unit is below its carrying amount, where necessary, the Company's goodwill and/or intangible asset with indefinite lives will be impaired at that time.

The Company performed its annual goodwill impairment assessment as of December 31, 2011, based on its qualitative assessment of macroeconomic, industry, and market events and circumstances as well as the overall financial performance subsequent to the November 2010 and September 2011 acquisition dates of the Green Mountain Energy and Energy Plus reporting units, respectively, the Company determined it was not more likely than not that the fair value of goodwill attributed to these reporting units was less than its carrying amount; as such, the annual two-step impairment test was deemed not necessary to be performed for these reporting units for the year ended December 31, 2011.

The Company performed step one of the two-step impairment test for its Texas reporting unit, NRG Texas, which is at the operating segment level. The Company determined the fair value of this reporting unit using primarily an income approach and then applied an overall market approach reasonableness test to reconcile that fair value with NRG's overall market capitalization. The Company believes the methodology and assumptions used in the valuation are consistent with the views of market participants. Significant inputs to the determination of fair value were as follows:

• For the three solid-fuel baseload plants that drive a majority of the value in the reporting unit, and for the region's Elbow Creek, Langford, Cedar Bayou and South Trent facilities, the Company applied a discounted cash flow methodology to their long-term budgets. This approach is consistent with that used to determine fair value in prior years. 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. Projected generation in the long-term budgets is based on management's estimate of supply and demand within the sub-markets for each plant and the physical and economic characteristics of each plant;

• For the reporting unit's remaining gas plants, the Company applied a market-derived earnings multiple to the gas plants' aggregate estimated 2011 earnings before interest, taxes, depreciation and amortization. This approach is consistent with that used to determine fair values in prior years; and

• The intangible value to NRG Texas for synergies it provides to the Retail Businesses was determined by capitalizing estimated annual collateral charge and supply cost savings.

Under step one, if the fair value of a reporting unit exceeds its carrying value, goodwill of the reporting unit is not considered impaired. Under the income approach described above, the Company estimated the fair value of NRG Texas' invested capital to exceed its carrying value by approximately 12% at December 31, 2011. The Company also evaluated various market-derived data including market research forecasts, recent merger and acquisition activity and earnings multiples, and together with its estimate of fair value, concluded that NRG Texas's goodwill is not impaired at December 31, 2011.

39

To reconcile the fair value determined under the income approach with NRG's market capitalization, the Company considered historical and future budgeted earnings measures to estimate the average percentage of total company value represented by NRG Texas, and applied this percentage to an adjusted business enterprise value of NRG. To derive this adjusted business enterprise value, the Company applied a range of control premiums based on recent market transactions to the business enterprise value of NRG on a non-controlling, marketable basis, and also made adjustments for some non-operating assets and for some of the significant factors that impact NRG differently from NRG Texas, such as environmental capital expenditures outside of the Texas region on NRG's stock price. The Company also qualitatively considered the impact on its stock price of shorter-term market views about forward natural gas prices. The Company was able to reconcile the proportional value of NRG Texas to NRG's market capitalization at a value that would not indicate an impairment.

The Company's estimate of fair value under the income approach described above is affected by assumptions about projected power prices, generation, fuel costs, capital expenditure requirements and environmental regulations, and the Company believes that the most significant impact arises from future power prices. The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates power plants. Due to recent downward trends in market natural gas prices, the Company performed a sensitivity scenario by using the quoted natural gas prices on the New York Mercantile Exchange, or NYMEX, as of December 31, 2011, and changes to the implied heat rate that would support new build of combined cycle gas plant in the Texas markets, coal and transportation charges, variable operations and maintenance costs, and the impact on forecasted generation for the baseload plants during the budget period. Under this sensitivity scenario, the fair value of NRG Texas was 16% below its carrying value at December 31, 2011. While not required, the Company further performed a high-level hypothetical step two analysis for this sensitivity scenario. Step two requires an allocation of fair value to the individual asset and liabilities using a hypothetical purchase price allocation in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded. Under the hypothetical step two for the sensitivity scenario it was determined that no goodwill impairment was necessary as of December 31, 2011. If long-term natural gas prices remain depressed for an extended period of time, the Company's goodwill may become impaired in the future, which would result in a non-cash charge, not to exceed $1.7 billion, related to the NRG Texas reporting unit.

Contingencies

NRG records a loss contingency when management determines it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Gain contingencies are not recorded until management determines it is certain that the future event will become or does become a reality. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. NRG describes in detail its contingencies in Item 15 — Note 22, Commitments and Contingencies, to the Consolidated Financial Statements.

Recent Accounting Developments

See Item 15 — Note 2, Summary of Significant Accounting Policies, to the Consolidated Financial Statements for a discussion of recent accounting developments.

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Item 7A — Quantitative and Qualitative Disclosures About Market Risk

NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk, liquidity risk, credit risk and currency exchange risk. In order to manage these risks the Company uses various fixed-price forward purchase and sales contracts, futures and option contracts traded on NYMEX, and swaps and options traded in the over-the-counter financial markets to:

• Manage and hedge fixed-price purchase and sales commitments;

• Manage and hedge exposure to variable rate debt obligations;

• Reduce exposure to the volatility of cash market prices, and

• Hedge fuel requirements for the Company's generating facilities.

Commodity Price Risk

Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities, and correlations between various commodities, such as natural gas, electricity, coal, oil, and emissions credits. NRG manages the commodity price risk of the Company's merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and fuel. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges, such as NYMEX and Intercontinental Exchange, or ICE, as well as over-the-counter markets. The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operation and other factors.

While some of the contracts the Company uses to manage risk represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. NRG uses the Company's best estimates to determine the fair value of those derivative contracts. However, it is likely that future market prices could vary from those used in recording mark-to-market derivative instrument valuation, and such variations could be material.

NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports, and Value at Risk, or VaR. NRG uses a Monte Carlo simulation based VaR model to estimate the potential loss in the fair value of the Company's energy assets and liabilities, which includes generation assets, load obligations, and bilateral physical and financial transactions. The key assumptions for the Company's VaR model include: (i) lognormal distribution of prices; (ii) one-day holding period; (iii)  95% confidence interval; (iv) rolling 36-month forward looking period; and (v) market implied volatilities and historical price correlations.

As of December 31, 2011, the VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions calculated using the VaR model, was $45 million.

The following table summarizes average, maximum and minimum VaR for NRG for the years ended December 31, 2011, and 2010:

(In millions)	2011		2010
VaR as of December 31,	$	45	$	50
For the year ended December 31,
Average	$	60	$	54
Maximum	77		70
Minimum	44		37

Due to the inherent limitations of statistical measures such as VaR, the evolving nature of the competitive markets for electricity and related derivatives, and the seasonality of changes in market prices, the VaR calculation may not capture the full extent of commodity price exposure. As a result, actual changes in the fair value of mark-to-market energy assets and liabilities could differ from the calculated VaR, and such changes could have a material impact on the Company's financial results.

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In order to provide additional information for comparative purposes to NRG's peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of December 31, 2011, for the entire term of these instruments entered into for both asset management and trading, was $13 million primarily driven by asset-backed transactions.

Interest Rate Risk

NRG is exposed to fluctuations in interest rates through the Company's issuance of fixed rate and variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG's risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.

NRG entered into interest rate swaps, which became effective on April 1, 2011, and are intended to hedge the risks associated with floating interest rates. For the interest rate swaps, the Company will pay its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives the monthly equivalent of a floating interest payment based on a 1-month London Inter-Bank Offer Rate, or LIBOR, calculated on the same notional value. All interest rate swap payments by NRG and its counterparties are made monthly and the LIBOR is determined in advance of each interest period. The total notional amount of the swaps, which mature on February 1, 2013, is $900 million.

In addition to those discussed above, the Company's project subsidiaries enter into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. See Item 15 - Note 12,Debt and Capital Leases, to the Consolidated Financial Statements, for more information about interest rate swaps of the Company's project subsidiaries.

If all of the above swaps had been discontinued on December 31, 2011, the Company would have owed the counterparties $100 million. Based on the investment grade rating of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.

As part of the CVSR financing, the Company entered into swaptions with a notional value of $686 million in order to hedge the project interest rate risk. If the swaptions were discontinued on December 31, 2011, the counterparty would have owed the Company approximately $27 million.

NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of December 31, 2011, a 1% change in interest rates would result in an $8 million change in interest expense on a rolling twelve month basis.

As of December 31, 2011, the fair value of the Company's debt was equal to its carrying value of $9.7 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt by $797 million.

Liquidity Risk

Liquidity risk arises from the general funding needs of NRG's activities and in the management of the Company's assets and liabilities. The Company is currently exposed to additional collateral posting if natural gas prices decline primarily due to the long natural gas equivalent position at various exchanges used to hedge NRG's retail supply load obligations.

Based on a sensitivity analysis for power and gas positions under marginable contracts, a $1 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $123 million as of December 31, 2011 and a 1.25 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $68 million as of December 31, 2011. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of December 31, 2011.

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Counterparty Credit Risk

Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits; (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk of the counterparty until positions settle.

As of December 31, 2011, counterparty credit exposure to a significant portion of the Company's counterparties was $1.2 billion and NRG held collateral (cash and letters of credit) against those positions of $261 million resulting in a net exposure of $919 million. Counterparty credit exposure is discounted at the risk free rate. The following table highlights the credit quality and the net counterparty credit exposure by industry sector. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. As of December 31, 2011, the exposure is shown net of collateral held, and includes amounts net of receivables or payables.

Category	Net Exposure (a) (% of Total)
Financial institutions	57	%
Utilities, energy merchants, marketers and other	39
Coal and emissions	1
ISOs	3
Total	100	%

Category	Net Exposure (a) (% of Total)
Investment grade	70	%
Non-rated (b)	27
Non-Investment grade	3
Total	100	%

(a) Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.

(b) For non-rated counterparties, the majority are related to ISO and municipal public power entities, which are considered investment grade equivalent ratings based on NRG's internal credit ratings.

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NRG has credit risk exposure to certain wholesale counterparties representing more than 10% of the total net exposure discussed above and the aggregate of credit risk exposure to such counterparties was $265 million. Approximately 89% of NRG's positions relating to this credit risk roll-off by the end of 2013. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company's financial position or results of operations from nonperformance by any of NRG's counterparties.

Counterparty credit exposure described above excludes credit risk exposure under certain long term contracts, including California tolling agreements, South Central load obligations, solar PPAs and a coal supply agreement. As external sources or observable market quotes are not available to estimate such exposure, the Company valued these contracts based on various 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. Based on these valuation techniques, as of December 31, 2011, credit risk exposure to these counterparties is approximately $866 million for the next five years. This amount excludes potential credit exposures for projects with long term PPAs that have not reached commercial operations. Many of these power contracts are with utilities or public power entities that have strong credit quality and specific public utility commission or other regulatory support. In the case of the coal supply agreement, NRG holds a lien against the underlying asset. These factors significantly reduce the risk of loss.

Retail Customer Credit Risk

NRG is exposed to retail credit risk through its retail electricity providers, which serve C&I customers and the Mass market. Retail credit risk results when a customer fails to pay for services rendered. The losses could be incurred from nonpayment of customer accounts receivable and any in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangements.

As of December 31, 2011, the Company's credit exposure to C&I customers was diversified across many customers and various industries, with a significant portion of the exposure with government entities.

NRG is also exposed to credit risk relating to its Mass customers, which may result in a write-off of bad debt. During 2011, the Company continued to experience improved customer payment behavior, but current economic conditions may affect the Company's customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense.

Credit Risk Related Contingent Features

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, or require the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts that have adequate assurance clauses that are in a net liability position as of December 31, 2011, was $69 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of December 31, 2011, was $35 million. The Company is also a party to certain marginable agreements where NRG has a net liability position but the counterparty has not called for the collateral due, which is approximately $15 million as of December 31, 2011.

Currency Exchange Risk

NRG's foreign earnings and investments may be subject to foreign currency exchange risk, which NRG generally does not hedge. As these earnings and investments are not material to NRG's consolidated results, the Company's foreign currency exposure is limited.

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